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TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on September 13, 2016

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

VANTAGE ENERGY INC.
(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		1311 (Primary Standard Industrial Classification Code Number)		46-5608050 (I.R.S. Employer Identification No.)

116 Inverness Drive East, Suite 107
Englewood, Colorado 80112
(303) 386-8600
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

Thomas B. Tyree, Jr.
President and Chief Financial Officer
116 Inverness Drive East, Suite 107
Englewood, Colorado 80112
(303) 386-8600
(Name, address, including zip code, and telephone number, including area code, of agent for service)


Copies to:
Douglas E. McWilliams Julian J. Seiguer Vinson & Elkins L.L.P. 1001 Fannin, Suite 2500 Houston, Texas 77002 (713) 758-2222		Matthew R. Pacey Eric M. Willis Kirkland & Ellis LLP 600 Travis Street, Suite 3300 Houston, Texas 77002 (713) 835-3600

Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Proposed Maximum Offering Price(1)(2)	Amount of Registration Fee(3)(4)




Common Stock, par value $0.01 per share	$100,000,000	$10,070

(1): Includes common stock issuable upon exercise of the underwriters' option to purchase additional common stock.
(2): Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended (the "Securities Act").
(3): To be paid in connection with the initial filing of the registration statement.
(4): A registration fee of $94,182.10 for 27,082,500 shares of common stock was previously paid in connection with the filing of a registration statement on Form S-1 (File No. 333-197265) on September 15, 2014. Pursuant to Rule 457(p) under the Securities Act, such previously paid registration fee is being used to offset the total registration fee due hereunder.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated September 13, 2016

PROSPECTUS

Vantage Energy Inc.

Common Stock

This is the initial public offering of the common stock of Vantage Energy Inc., a Delaware corporation. We are offering shares of our common stock. No public market currently exists for our common stock. We are an "emerging growth company" and are eligible for reduced reporting requirements. Please see "Prospectus Summary — Emerging Growth Company Status".

We have applied to list our common stock on the New York Stock Exchange under the symbol "VEI".

We anticipate that the initial public offering price will be between $ and $ per share.

Investing in our common stock involves risks. Please see "Risk Factors" beginning on page 22 of this prospectus.

(1): Please see "Underwriting" for a description of all underwriting compensation payable in connection with this offering.

We have granted the underwriters the option to purchase up to additional shares of common stock on the same terms and conditions set forth above if the underwriters sell more than shares of common stock in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares on or about , 2016.

Joint Book-Running Managers


Goldman, Sachs & Co.	Barclays	Credit Suisse
Citigroup	J.P. Morgan	Wells Fargo Securities


Senior Co-Managers
BofA Merrill Lynch		Capital One Securities
Deutsche Bank Securities		KeyBanc Capital Markets
SunTrust Robinson Humphrey		Tudor, Pickering, Holt & Co.


Co-Managers
ABN AMRO	Baird	BOK Financial Securities, Inc.
Fifth Third Securities	Heikkinen Energy Advisors	Williams Trading, LLC

Prospectus dated , 2016

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TABLE OF CONTENTS


PROSPECTUS SUMMARY		1
RISK FACTORS		22
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		56
USE OF PROCEEDS		58
DIVIDEND POLICY		59
CAPITALIZATION		60
DILUTION		62
SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA		64
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		67
BUSINESS		114
MANAGEMENT		147
EXECUTIVE COMPENSATION		155
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		163
CORPORATE REORGANIZATION		165
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		168
DESCRIPTION OF CAPITAL STOCK		170
SHARES ELIGIBLE FOR FUTURE SALE		175
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS		177
UNDERWRITING		182
LEGAL MATTERS		188
EXPERTS		188
WHERE YOU CAN FIND MORE INFORMATION		188
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS		F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS		A-1

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of common stock and seeking offers to buy shares of common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please see "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements".

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

•: "Vantage", "we", "our", "us" or like terms refer collectively to our predecessor and Vantage I, together with their consolidated subsidiaries before the completion of our corporate reorganization described in "Corporate Reorganization" (except as otherwise disclosed) and to Vantage Energy Inc. and its consolidated subsidiaries, including Vantage I and Vantage II, as of and following the completion of our corporate reorganization;
•: "Vantage I" refers to Vantage Energy, LLC;
•: "Vantage II" refers to Vantage Energy II, LLC;
•: "Vantage II Alpha" refers to Vantage Energy II Alpha, LLC;
•: "Vantage II Consolidation" refers to the merger of Vantage II Alpha with and into Vantage II or its direct or indirect wholly owned subsidiary that will be completed prior to our corporate reorganization;
•: "Vantage Investment I" refers to Vantage Energy Investment LLC;
•: "Vantage Investment II" refers to Vantage Energy Investment II LLC;
•: "Alpha Acquisition" refers to Vantage II Alpha's June 2016 acquisition of certain natural gas properties located in Greene County, Pennsylvania from a wholly owned subsidiary of Alpha Natural Resources, Inc. ("Alpha Natural Resources");
•: "Existing Owners" refers, collectively, to the Sponsors and the Management Members that own equity interests in Vantage I, Vantage II and Vantage II Alpha prior to the completion of our corporate reorganization and in Vantage Investment I, Vantage Investment II and us directly as of and following the completion of our corporate reorganization;
•: "Management Members" refers, collectively, to our individual officers and employees and other individuals who, together with the Sponsors, initially formed Vantage I, Vantage II and Vantage II Alpha;
•: "our predecessor" or "Predecessor" refer, collectively, to (a) Vantage II and its consolidated subsidiaries and (b) for the periods after the closing of the Alpha Acquisition and prior to the completion of the Vantage II Consolidation, Vantage II Alpha; and
•: "Sponsors" refers, collectively, to investment funds affiliated with or managed by Quantum Energy Partners ("Quantum"), Riverstone Holdings LLC ("Riverstone") and Lime Rock Partners ("Lime Rock").

We have also included a glossary of some of the oil and natural gas industry terms used in this prospectus in Annex A to this prospectus.

Presentation of Financial and Operating Data

Unless otherwise indicated, the summary historical consolidated financial information presented in this prospectus is that of our predecessor. The financial information of our predecessor presented in this prospectus treats the Vantage II Consolidation as a reorganization of entities under common control. The pro forma financial information presented in this prospectus treats the combination of Vantage I and Vantage II in connection with our corporate reorganization as an acquisition in a business combination of Vantage I by our predecessor. Please see "Corporate

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Reorganization" and the unaudited pro forma financial statements included elsewhere in this prospectus.

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of our predecessor and Vantage I on a combined basis as of the dates and for the periods presented. Unless another date is specified, (a) all acreage, well count, hedging and drilling location data presented in this prospectus is as of June 30, 2016 and (b) all other financial, reserve and operational data presented in this prospectus in respect of dates or periods occurring prior to the consummation of the Alpha Acquisition does not include the assets or operations acquired in the Alpha Acquisition. Unless otherwise noted, references to production volumes refer to sales volumes net to our interests.

Certain amounts and percentages included in this prospectus have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled "Risk Factors". These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties' trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.

iii

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PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read this entire prospectus and the documents to which we refer you before making an investment decision. You should carefully consider the information set forth under "Risk Factors", "Cautionary Statement Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical and pro forma financial statements and the related notes to those financial statements included elsewhere in this prospectus. Where applicable, we have assumed an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus). Unless otherwise indicated, the information presented in this prospectus assumes that the underwriters' option to purchase additional shares of common stock is not exercised. Unless otherwise indicated, the estimated reserve volumes, estimated reserve values and EURs presented in this prospectus were prepared by our independent reserve engineers based on the Securities and Exchange Commission ("SEC") pricing at December 31, 2015, as described in "— Reserve and Operating Data". Certain operational terms used in this prospectus are defined in the "Glossary of Oil and Natural Gas Terms" set forth in Annex A hereto.

Our Company

We are a growth-oriented, independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties in the United States, with a focus on the Appalachian Basin. We are the largest leaseholder in Greene County, Pennsylvania, an area with significant dry natural gas resources and stacked reservoirs. We hold a largely contiguous acreage position in what we believe to be the core of the Marcellus, Upper Devonian and Utica Shales. Additionally, we have a sizeable position in what we believe to be the core of the Barnett Shale in Texas. We believe these areas are among the most prolific unconventional resource plays in North America, and are generally characterized by high well recoveries relative to drilling and completion costs, predictable production profiles, significant hydrocarbons in place and constructive operating environments.

We own interests in 88,634 net acres in Greene County, of which 13,642 acres are held in fee and 5,027 of such fee acres are leased to third parties. We believe that substantially all of this acreage is prospective for the Marcellus, Upper Devonian and Utica Shales. The Marcellus Shale is the largest unconventional natural gas field in the U.S. and the Upper Devonian and Utica Shales are stacked reservoirs above and below the Marcellus Shale, respectively. Based on our drilling results, as well as drilling results publicly released by other operators, we believe that the Marcellus Shale in Greene County offers some of the most attractive single-well rates of return in North America.

We own and operate midstream infrastructure in Greene County, including a natural gas gathering system with complementary water sourcing and distribution assets (see "— Midstream"). We gather all of our operated natural gas production in Greene County and believe that our system will support our future production growth. We believe that Greene County is among the best-served areas in the Appalachian Basin by current and planned infrastructure, and due to this access has the greatest potential for natural gas production growth in the Appalachian Basin. In addition to our midstream system, a number of long-haul transmission pipelines converge in Greene County, including Spectra Energy Partners' TETCo system, Dominion Resources' DTI system, Columbia Gas Transmission's T system, National Fuel Gas' Line N system and EQT Midstream's Equitrans system. The energy content of our Appalachian Basin dry natural gas production, which ranges from 1,000 to 1,060 MBtu/Mcf, enables us to capture incremental revenue on a volumetric basis, while also meeting the specifications of these long-haul transmission pipelines, thereby allowing us to avoid additional processing and blending expenses.

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Marcellus and Upper Devonian Shale wells drilled in Greene County have on average the second highest and highest initial production ("IP") rates, respectively, of any county in Pennsylvania. Additionally, operators in Greene County recently completed multiple wells in the Utica Shale in close proximity to our acreage and disclosed 24-hour IP rates as high as 72.9 MMcfe/d. The following charts show the 90-day IP rates for wells drilled in 2015 in the Marcellus and Upper Devonian Shales by county in Pennsylvania.


Marcellus Shale 90-Day Initial Production		Upper Devonian Shale 90-Day Initial Production

Source: Drillinginfo

In addition to our Appalachian Basin acreage, we have 37,481 net acres in the Barnett Shale, of which 22,623 net acres are located in what we believe to be the core of the Barnett Shale in Tarrant, Denton and Wise Counties in Texas. Covering over 5,000 square miles and 18 counties in North Texas, the Barnett Shale was the first shale reservoir to be successfully exploited using horizontal drilling and fracture stimulation techniques. The Barnett Shale remains one of the most productive shale plays in North America and produced 4.4 Bcf/d of natural gas in 2015 according to the Texas Railroad Commission.

Our management team has a proven track record of implementing technically driven growth strategies to target best-in-class returns in some of the most prominent unconventional plays across the United States. Roger Biemans, our Chairman and Chief Executive Officer, and Tom Tyree, our President and Chief Financial Officer, founded our company with investments from affiliates of Quantum Energy Partners, Riverstone Holdings LLC and Lime Rock Partners. We made our initial entry into the Barnett Shale in 2007 and the Appalachian Basin in 2010. Since then, we have been committed to a strategy of disciplined growth through acquisitions and development drilling in the highest quality areas of these plays.

We efficiently exploit our resource base by applying and integrating micro-seismic technology, 3D seismic interpretation and petro-physical core analysis to define the reservoir and optimize formation targeting. This subsurface expertise translates to value maximizing inter-well spacing and highly economic development realized through best-in-class drilling, completion and operational strategies, including multi-well pad drilling, fit for purpose rig utilization, advanced down hole steering, targeted reservoir stimulation and optimized flow back practices. In addition, we have significant experience in our operating areas. We operate 80 gross horizontal wells in the Marcellus Shale, four gross horizontal wells in the Upper Devonian Shale and 185 gross horizontal wells in the Barnett Shale. We believe that our horizontal drilling and completion expertise, coupled with the favorable geologic characteristics of our Appalachian Basin and Barnett Shale acreage, positions us for continued strong well economics and growth. We have organically grown our net daily

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production from 18 MMcfe/d for the year ended December 31, 2011 to 398.5 MMcfe/d for the three months ended June 30, 2016, representing a compounded annual growth rate of 98.7%.

The following chart shows the growth in our average net daily production in the Appalachian Basin and Barnett Shale since 2011.

Average Net Daily
Production (MMcfe/d)

(1): CAGR stands for compounded annual growth rate.
(2): Includes 5.4 MMcfe/d of average daily production for the three months ended June 30, 2016 associated with a royalty interest acquired in the Alpha Acquisition.

During 2015, we ran a two rig drilling program with one rig operating in the Appalachian Basin and one rig operating in the Barnett Shale. In 2015, we completed 73 wells on our acreage, including 31 wells in the Appalachian Basin and 42 wells in the Barnett Shale. After temporarily reducing the pace of our drilling and completions activities in the first half of 2016 due to depressed commodity prices, we are currently running two rigs in the Marcellus Shale with the intention of adding a third rig in the Marcellus Shale by year end. Due to our temporary reduction in the pace of our drilling and completion activities in the first half of 2016, our average daily production in the second half of 2016 is anticipated to be lower than our average daily production in the first half of 2016. As a result of our increased drilling and completion activities in the second half of 2016, we anticipate that our average daily production in the first half of 2017 will be materially higher than our average daily production in the second half of 2016. We retain the flexibility to adjust our rig count based on the commodity price environment and other factors. As of June 30, 2016, we had 1,361 identified drilling locations, including 769 in the Marcellus Shale, 210 in the Upper Devonian Shale, 153 in the Utica Shale and 229 in the Barnett Shale.

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Reserve and Operating Data

The following table provides information regarding our proved reserves as of December 31, 2015 and our average net daily production for the three months ended June 30, 2016.


	Estimated Proved Reserves⁽¹⁾⁽²⁾											Average Net Daily

	Natural Gas (Bcf)		NGLs (MMBbls)		Oil (MMBbls)		Total (Bcfe)		% Proved Developed			Production (MMcfe/d)⁽³⁾

Marcellus Shale		1,220		—		—		1,220		38	%		259.8
Upper Devonian Shale		63		—		—		63		26	%		8.2

Total Appalachian Basin		1,283		—		—		1,283		38	%		268.0
Barnett Shale⁽⁴⁾		472		24		1		622		46	%		130.5

Total		1,755		24		1		1,905		40	%		398.5

(1): Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. As of December 31, 2015, the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months (the "SEC Price Deck") were $2.59/Mcf for natural gas, $16.22/Bbl for NGLs and $50.28/Bbl for oil, representing the prices for Henry Hub natural gas, Mont Belvieu NGLs, and WTI oil, respectively. In determining our reserves, the SEC Price Deck was adjusted by field or lease for quality, transportation fees, regional price differentials and other factors affecting the price received at the wellhead. The corresponding natural gas prices proximate to our operating areas were $1.39/Mcf and $2.47/Mcf for Dominion South Point and WAHA, respectively. There were no proved reserves associated with our Utica Shale acreage as of December 31, 2015.
(2): The reserve data presented is that of Vantage II and Vantage I on a combined basis as of December 31, 2015, assuming a 30-year reserve life.
(3): Includes 5.4 MMcfe/d of average daily production for the three months ended June 30, 2016 associated with a royalty interest acquired in the Alpha Acquisition.
(4): Includes de minimis reserves and production attributable to our other properties.

The following table provides certain information regarding our Appalachian Basin and Barnett Shale assets and operations as of June 30, 2016 except as otherwise noted.


	Effective Horizontal Acreage(1)			Identified Drilling Locations(2)		Net Producing Lateral Feet(3) (in thousands)		Net Undeveloped Identified Lateral Feet(4) (in thousands)		Net Producing/ Total Lateral Feet(3)(5)			Weighted Average Working Interest			Weighted Average Net Revenue Interest(6)			Average PUD EUR per 1,000 Feet(7) (Bcfe)		Average PUD D&C per 1,000 Feet(8) (in thousands)

Appalachian Basin
Marcellus Shale		85,047			769		369		3,965		8.5	%		81.7	%		68.7	%		1.93		$	834
Upper Devonian Shale		84,299			210		21		1,079		1.9	%		80.4	%		67.5	%		1.58		738
Utica Shale		51,907			153		—		521		0.0	%		58.8	%		50.9	%		—		—
Barnett Shale		37,481			229		691		848		44.9	%		68.0	%		52.8	%		1.03		428

Total		258,734	(9)		1,361		1,081		6,413		14.4	%		76.6	%(10)		63.9	%(10)

(1): We refer to the summation of our horizontal acreage across the multiple target formations as our "Effective Horizontal Acreage". We believe this acreage metric more accurately conveys our horizontal drilling opportunities in our target formations than our total surface acreage, and we believe our analysis of engineering, geological, geochemical and seismic data to estimate our horizontal drilling opportunities is based on industry standards. Our calculation of our Effective Horizontal Acreage is an inexact estimate. We cannot represent that the Effective Horizontal Acreage in each of our target formations is prospective for such formation. Additionally, we cannot represent what portion of our Effective Horizontal Acreage will ultimately be drilled. See "Risk Factors — Risks Related to Our Business — Our Effective Horizontal Acreage is based on our and other operators' current drilling results and our interpretation of available geologic and engineering data and therefore is an inexact estimate subject to various uncertainties". In the Appalachian Basin, 13,642 net acres are held in fee and 5,027 of such fee acres are leased to third parties.
(2): Includes 84, 6 and 112 identified drilling locations associated with proved undeveloped reserves as of December 31, 2015 on our Marcellus Shale, Upper Devonian Shale and Barnett Shale acreage, respectively. For a discussion of how we identify drilling locations, a portion of which constitute estimated locations based on our acreage and spacing assumptions, please see "Business — Our Operations — Reserve Data — Determination of Identified Drilling Locations".
(3): Net Producing Lateral Feet is calculated by multiplying the working interest for each of our producing wells in a reservoir by the lateral length of such well.
(4): Net undeveloped identified lateral feet is calculated by multiplying the working interest for each of our identified drilling locations in a reservoir by the expected lateral length of such identified drilling location. The average lateral length for our identified drilling locations is 6,345, 6,447, 5,777 and 5,448 feet for the Marcellus, Upper Devonian, Utica and Barnett Shales, respectively.

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(5): Total Lateral Feet is calculated by adding Net Producing Lateral Feet and Net Undeveloped Identified Lateral Feet in a reservoir. Management believes that the ratio of Net Producing Lateral Feet to Total Lateral Feet is useful because it provides investors a method for evaluating the estimated future production associated with our identified drilling locations.
(6): Represents the average net revenue interest associated with our weighted average working interest in our drilling locations. Our average net revenue interest equals our working interest percentage multiplied by the net revenue interest.
(7): Represents the average EUR per 1,000 feet of horizontal lateral associated with the proved undeveloped reserves reflected in our reserve reports as of December 31, 2015, which assumed a 30-year reserve life.
(8): Represents the expected average drilling and completion cost per 1,000 feet of horizontal lateral (in thousands), as reviewed by our third-party auditors, associated with the proved undeveloped reserves reflected in our reserve report as of December 31, 2015, which assumed a 30-year reserve life.
(9): Effective Horizontal Acreage is represented in multiple stacked reservoirs and therefore represents a multiple of our total acreage. This acreage metric represents what we believe to be our combined horizontal acreage position that is prospective for hydrocarbon production underneath our total surface acreage. Our total net surface acreage in the Appalachian Basin and the Barnett Shale as of June 30, 2016, was 88,634 acres and 37,481 acres, respectively.
(10): Represents a weighted average calculated using the number of identified drilling locations in the respective reservoir.

Midstream

We own and operate midstream infrastructure in Greene County, including a natural gas gathering system with complementary water sourcing and distribution assets. We believe our ownership of this midstream infrastructure allows us to reduce our costs, promote overall efficiency of operations and increase our rates of return. We gather all of our operated natural gas production in Greene County and believe that our system will support our future production growth. We also intend to seek out commercial third-party gathering and water opportunities on our system.

Our natural gas gathering infrastructure currently has a demonstrated throughput capacity of over 400 MMcf/d and includes approximately 30 miles of gathering pipeline and 7,100 horsepower of compression. For the six months ended June 30, 2016, gross throughput on our midstream system was 325 MMcf/d, 59 MMcf/d of which was attributable to our joint venture partner's interest in the system, representing a 63% increase from the corresponding period in 2015. Our midstream segment generated pro forma Midstream Segment Adjusted EBITDA of $22.4 million for the six months ended June 30, 2016, compared to $12.5 million for the corresponding period in 2015.

Our natural gas gathering system is designed to grow to an ultimate total throughput capacity of approximately 1,800 MMcf/d with 147 miles of pipeline and 145,000 horsepower of compression. We intend to expand our existing system over time to meet our expected production growth, including increasing our throughput capacity to approximately 600 MMcf/d by 2018 and approximately 1,000 MMcf/d by 2022. Our water sourcing and distribution system is designed for a total supply of 118,000 Bbls/d. We expect the buildout of our water sourcing and distribution system to accommodate the expected future growth of our development activities.

We do not currently own or operate midstream infrastructure in the Barnett Shale and rely on third-party service providers for the gathering of our production in that basin.

Marketing

We routinely manage our commodity and regional price risk through hedging arrangements, firm marketing agreements and active analysis of primary and secondary firm transportation opportunities. As part of our marketing activities, we continually review regional supply and demand fundamentals with a focus on current and forecasted long-haul pipeline utilization. In addition to the numerous takeaway capacity alternatives currently available to producers in Greene County, we believe that planned takeaway capacity additions of approximately 17 Bcf/d expected to come online by December 2018 will be sufficient to meet expected supply growth from producers in and around Greene County for the foreseeable future. Significant new takeaway projects include Tallgrass Energy's Rockies Express Zone 3 Capacity Enhancement, Energy Transfer's Rover Pipeline, Nexus Gas Transmission, Spectra Energy Partners' TETCo Gulf Markets Expansion, multiple Columbia Pipeline Group projects, Dominion Resources' Atlantic Coast Project and EQT's Mountain Valley Pipeline. See "Business — Our Properties — Midstream — Marketing".

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The following table provides a summary of our hedge position as of July 31, 2016:


Commodity Swaps	Aug. – Dec. 2016		2017	2018	2019
Natural Gas
Waha Fixed Price (MMBtu/d)		85,000	56,507	22,397	9,137
Waha Fixed Price ($/MMBtu)		$2.97	$3.07	$3.01	$3.29
Dominion South Point Fixed Price (MMBtu/d)		215,209	200,000	147,260	27,260
Dominion South Point Fixed Price ($/MMBtu)		$2.10	$2.26	$2.30	$2.58
NGLs (bbl/d)		1,499	500	—	—
Mt. Belvieu ($/bbl)		$16.78	$15.13	$0.00	$0.00
Oil (bbl/d)		85	50	—	—
NYMEX WTI ($/bbl)		$45.66	$44.60	$0.00	$0.00

⁽¹⁾: Represents the average daily volume of such commodity swaps during the indicated periods. These hedged volumes are not allocated evenly over the periods presented.

Capital Program

Our 2016 capital program is primarily focused on developing low-cost, high-return drilling and midstream opportunities in order to grow production and cash flow.

We are currently running two rigs in the Marcellus Shale with the intention of adding a third rig in the Marcellus Shale by year end, and we retain the flexibility to adjust our rig count based on the commodity price environment and other factors.

For the months ended December 31, 2017, we plan to invest up to $ million in capital expenditures as follows:


		Base⁽¹⁾
Drilling and Completion		$
Number of Wells Drilled and Cased
Leasehold Acquisitions		$
Midstream		$

Total		$

(1): Assumes a third rig will be added in the Appalachian Basin during the three months ended .

By operating the substantial majority of our acreage, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for natural gas, NGLs and oil, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions and drilling and acquisition costs. Any reduction in our capital expenditure budget could have the effect of delaying or limiting our development program, which would negatively impact our ability to grow production and could materially and adversely affect our future business, financial condition, results of operations or liquidity.

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Business Strategy

Our strategy is to leverage our management team's experience in identifying, acquiring and developing economic natural gas and oil resources to cost efficiently grow our reserves, production and cash flow and thus maximize the value of our assets. Our strategy has the following principal elements:

•: Growing shareholder value through optimizing development of our extensive drilling inventory. We began our Barnett Shale development program in 2008 and our Appalachian Basin development program in 2011, and we have increased production from 18 MMcfe/d for the year ended December 31, 2011 to approximately 398.5 MMcfe/d for the three months ended June 30, 2016. We intend to continue to drill and develop our portfolio of 1,361 identified drilling locations with the goal of growing production, cash flow and reserves in an economically efficient manner in order to maximize shareholder value. We are currently running two rigs in the Marcellus Shale with the intention of adding a third rig in the Marcellus Shale by year end, and we retain the flexibility to adjust our rig count based on the commodity price environment and other factors.
•: Enhancing returns by focusing on capital and operating cost efficiencies. We target best-in-class returns in the Appalachian Basin and Barnett Shale. As the operator of the substantial majority of our acreage, we are able to manage the timing and level of our capital spending, our exploration and development strategies and our operating costs. We aim to maximize well production and recoveries relative to drilling and completion costs through optimizing lateral length, the number and distribution of frac stages, perforation cluster spacing and the type of fracture stimulation employed. We believe we have distinctive competencies in managing costs, and as a result, we believe we will continue to capture incremental capital and operating cost efficiencies.
•: Continue growing our acreage position in the core of the Appalachian Basin through opportunistic leasing and acquisitions. We have selectively built our Appalachian Basin position from less than 200 net acres as of December 31, 2010 to approximately 88,634 net acres, of which 13,642 acres are held in fee and 5,027 of such fee acres are leased to third parties. We believe that the Appalachian Basin continues to have significant expansion and consolidation opportunities, and we intend to pursue transactions that meet our strategic and financial objectives, such as our recent 31,323 net acre acquisition from Alpha Natural Resources. We are currently focused on acreage swaps and infill lease acquisitions that we believe will further consolidate our acreage, increase net lateral lengths and result in operational efficiencies.
•: Utilizing our midstream infrastructure to support upstream operations and enhance access to markets for our natural gas production. The midstream infrastructure we own and operate in Greene County gathers all of our operated natural gas production in the Appalachian Basin. Going forward, we expect to continue to invest in our Greene County gas gathering and water systems to (i) optimize our gathering and takeaway capacity, including access to interstate pipelines, (ii) support our expected production growth, (iii) provide greater control over the direction and planning of our drilling schedule, (iv) achieve lower capital and operating costs and generate overall efficiencies and (v) provide gathering and water services to third parties.
•: Managing commodity price exposure through an active hedging and marketing program to protect our expected future cash flows. We maintain an active commodity price risk management program through hedging, firm marketing arrangements and continuing analysis of primary and secondary firm transportation opportunities. We have historically hedged through basis using primarily fixed price swap contracts at liquid pricing

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benchmarks to reduce our exposure to price volatility in the underlying commodity as well as regional pricing differentials.

Business Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy and grow stockholder value, including:

•: Large and highly contiguous land position in the core of the Appalachian Basin. Since 2010, we have built a largely contiguous acreage position of 88,634 net acres in the Appalachian Basin through a disciplined and focused leasing and acquisition program. We are the largest leaseholder in Greene County, which we believe to be the dry natural gas core of the Marcellus, Upper Devonian and Utica Shales. We benefit from our concentrated, core position through our high net revenue interest and operational efficiencies. We believe our Marcellus Shale acreage offers some of the most attractive single-well rates of return in North America.
•: Multi-year, low-risk drilling inventory. We believe our concentrated acreage positions in the Appalachian Basin and Barnett Shale are well delineated, characterized by low geological risk and possess repeatable drilling opportunities that we expect will result in a predictable production growth profile. As of June 30, 2016, we had 1,361 identified drilling locations, including 769 in the Marcellus Shale, 210 in the Upper Devonian Shale, 153 in the Utica Shale and 229 in the Barnett Shale. Assuming a two rig program, our drilling inventory is approximately 22 years based on our Marcellus Shale locations and approximately 32 years when including our Upper Devonian and Utica Shale locations. We believe that we and other operators in the area have substantially delineated and de-risked our acreage position in the Marcellus and Barnett Shales. Likewise, we believe the drilling activity and well results of other operators in the area have substantially reduced the risk associated with our drilling locations in the Upper Devonian and Utica Shales.
•: Efficient operations drive low drilling and completion costs resulting in higher returns. We have historically had an intense focus on managing costs which has translated into meaningful reductions in our overall drilling and completion costs. We have implemented operational efficiencies to continue lowering our costs, such as pad drilling and the use of less expensive, shallow vertical drilling rigs to drill to the kick-off point of the horizontal wellbore, and optimized well spacing and completion designs. Our average drilling and completion cost, normalized for each 1,000 feet of horizontal lateral, decreased by 38% for the first half of 2016 compared to the three months ended December 31, 2014.
•: Exceptionally low operating cost structure with significant control across our acreage position. Our acreage position in the Appalachian Basin and Barnett Shale is generally in contiguous blocks which allows us to conduct our operations more cost effectively and develop this acreage more efficiently. Additionally, our operational control allows us to more efficiently manage the pace of development activities, the gathering and marketing of our production and operating costs. We are continually looking to increase efficiencies and decrease our operating cost structure and were able to achieve a lease operating expense per Mcfe of $0.13 for the three months ended June 30, 2016, a reduction of 66% compared to the three months ended December 31, 2014. This reduction was largely attributable to a shift toward recycling substantially all of our produced water in Greene County. Our company, which was comprised of just 63 employees at December 31, 2015, managed total production of 398.5 MMcfe/d for the three months ended June 30, 2016 and deployed $354 million in capital expenditures during the year ended December 31, 2015. Our general and

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administrative expense per Mcfe was $0.12 for the three months ended June 30, 2016, a reduction of 52% compared to $0.25 for the three months ended December 31, 2014.

•: Strategic, efficient midstream infrastructure supports production growth and access to markets. We gather all of our operated natural gas production in Greene County, and the concentrated nature of our stacked pay acreage in that area allows us to build out and operate our midstream infrastructure in a manner that captures significant capital and operating cost efficiencies. For the three months ended December 31, 2014 and June 30, 2016, our midstream operating expense was approximately $0.04 per Mcf based on our Appalachian Basin throughput volumes. Additionally, our natural gas gathering system is strategically located with interconnections to multiple downstream pipeline systems including TETCo and Dominion interstate pipelines.
•: Complementary position in the core of the Barnett Shale. We have assembled a large and attractive leasehold position of approximately 37,481 net acres in the Barnett Shale, including approximately 22,623 net acres in Tarrant, Denton, and Wise Counties in Texas, which we believe constitute the core of the Barnett Shale. Our Barnett Shale acreage position is characterized by mature, long-lived production profiles that provides us with access to multiple markets and favorable WAHA-based pricing.
•: Strong commodity price risk management protects capital investment. Our focus on commodity price risk management through hedging, firm marketing agreements and firm transportation opportunities protects our capital investment and future cash flows by reducing exposure to commodity prices. As of July 31, 2016, we had entered into hedging contracts through December 31, 2019 covering approximately 219 TBtu of future natural gas, NGLs and oil production. Substantially all of the natural gas hedges are linked to Dominion South Point and WAHA price indices, consistent with the pricing we receive for our natural gas production. The weighted average prices of our WAHA and Dominion South Point natural gas hedges are $3.04 and $2.26 per MMbtu, respectively. Inclusive of our NGLs and oil hedges, the weighted average price of our hedging contracts was $2.43 per MMbtu.
•: Significant liquidity and financial flexibility. Following the completion of this offering, we estimate that we will have availability under our new revolving credit facility of approximately $ million and $ million of cash on hand. After giving effect to this offering, we expect that our capital expenditures through 2017 will be fully funded with proceeds from this offering, cash flows from operations and available capacity under our new revolving credit facility, consistent with our overall financial strategy of maintaining a strong and stable capitalization profile.
•: Proven, experienced and incentivized management and technical teams. We believe our management team's experience and expertise across multiple resource plays provides a distinct competitive advantage. Our management team has an average of over 25 years of industry experience including executive officer positions at public exploration and production companies and key members with significant experience operating in the Appalachian Basin and Barnett Shale. We have assembled a strong technical staff of engineers, geoscientists and field operations managers with extensive experience in horizontal development and operating multi-rig development programs. We have been early adopters of new oilfield service technologies and techniques for drilling and completions. Our management and technical teams have a significant economic interest in us through their interests in our controlling stockholders, Vantage Investment I and Vantage Investment II.

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Recent Developments

Alpha Acquisition

On May 16, 2016, we entered into a purchase and sale agreement with a wholly owned subsidiary of Alpha Natural Resources to purchase certain natural gas properties located in Greene County (the "Alpha Properties") for cash consideration of $339.5 million, subject to post-closing adjustment (the "Alpha Acquisition"). The Alpha Properties consist of approximately 31,323 net acres, of which 5,027 acres are held in fee and leased to third parties, along with non-operating royalty interests in 42 producing Marcellus horizontal wells and certain related midstream and other assets. The Alpha Acquisition was completed in June 2016, with an effective date of April 1, 2016. The Alpha Acquisition added 330 identified drilling locations, including 226 in the Marcellus Shale, 72 in the Upper Devonian Shale and 32 in the Utica Shale.

Midstream Acquisition

We entered into two purchase and sale agreements (the "AMS Purchase Agreements") with Appalachia Midstream Services, L.L.C. ("Seller") to purchase certain midstream assets in Greene County (the "AMS Acquisition"). The AMS Acquisition consists of the remaining 62% interest not currently owned in the Rogersville Gas System and a 67.5% interest in the Wind Ridge Gathering System.

The aggregate purchase price was $50.0 million in cash and the AMS Purchase Agreement contains customary representations and warranties, covenants and indemnification provisions, and has an effective date of April 1, 2016. We and the Seller expect to close the AMS Acquisition in the third quarter of 2016.

Risk Factors

An investment in our common stock involves a number of risks that include the speculative nature of oil and natural gas exploration, competition, volatile commodity prices and other material factors. You should carefully consider, in addition to the other information contained in this prospectus, the risks described in "Risk Factors" before investing in our common stock. These risks could materially affect our business, financial condition and results of operations and cause the trading price of our common stock to decline. You could lose part or all of your investment. You should bear in mind, in reviewing this prospectus, that past experience is no indication of future performance. You should read "Cautionary Statement Regarding Forward-Looking Statements" for a discussion of what types of statements are forward-looking statements, as well as the significance of such statements in the context of this prospectus.

Corporate Reorganization

We have incorporated under the laws of the State of Delaware to become a holding company for Vantage's assets and operations. Vantage I was founded in December 2006 with equity commitments from affiliates of Quantum, Riverstone and Lime Rock, as well the Management Members. Subsequently, Vantage II was founded in July 2012 with equity commitments from affiliates of those same Sponsors and the Management Members. The Vantage II Consolidation will occur prior to our corporate reorganization described below.

Pursuant to the terms of a corporate reorganization that will be completed simultaneously with the closing of this offering, (i) Vantage I and Vantage II will merge into subsidiaries of newly-formed holding companies, Vantage Investment I and Vantage Investment II, that will be owned by the Existing Owners in equal proportions to their current ownership of Vantage I and Vantage II and (ii) Vantage Investment I and Vantage Investment II will contribute all of the interests in Vantage I

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and Vantage II to us in exchange for all of our issued and outstanding shares of common stock (prior to the issuance of shares of common stock in this offering). Following this offering, Vantage Investment I and Vantage Investment II will distribute to the Management Members a portion of the shares of common stock associated with such Management Members' initial investments in Vantage I and Vantage II, who will then hold the shares of common stock directly. As a result of the reorganization, Vantage I and Vantage II will become direct, wholly owned subsidiaries of Vantage Energy Inc.

We were incorporated to serve as the issuer in this offering and have no previous operations, assets or liabilities. As a result, we do not qualify as the accounting acquirer. Accordingly, in the corporate reorganization, the combination of our predecessor into us will be accounted for at historical cost, and the combination of Vantage I into us will be accounted for at fair value as a business combination by applying the acquisition method. For more information on our reorganization and the ownership of our common stock by our principal stockholders, please see "Corporate Reorganization", "Security Ownership of Certain Beneficial Owners and Management" and the unaudited pro forma financial statements included elsewhere in this prospectus.

The following diagram indicates our simplified ownership structure after giving effect to our corporate reorganization and this offering (assuming that the underwriters' option to purchase additional shares is not exercised).

Our Principal Stockholders

Following the completion of this offering and our corporate reorganization, Vantage Investment I, Vantage Investment II and the Management Members will directly own %, %

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and %, respectively, of our common stock, or %, % and %, respectively, if the underwriters' option to purchase additional shares is exercised in full. Vantage Investment I and Vantage Investment II are controlled by Quantum, Riverstone and Lime Rock. Please see "Corporate Reorganization".

Quantum is a Houston-based private investment firm founded in 1998. Focused exclusively on the energy sector, Quantum has built one of the leading energy private equity franchises and has managed more than $11 billion of equity commitments since its inception. Quantum has invested in and built over 70 companies in the upstream, midstream, oil field service and power sectors, both domestically and globally.

Riverstone is an energy and power-focused private investment firm founded in 2000 with approximately $34 billion of capital raised. Riverstone conducts buyout and growth capital investments in the exploration and production, midstream, oilfield services, power, and renewable sectors of the energy industry. With offices in New York, London, Houston and Mexico City, as of June 30, 2016, the firm has committed approximately $30 billion to 120 investments in North America, Latin America, Europe, Africa and Asia.

Established in 1998, Lime Rock Management LP ("Lime Rock Management") has raised approximately $6.8 billion in private equity funds for investment in the energy industry through Lime Rock Partners ("Lime Rock"), investors of growth capital in exploration and production and oilfield services companies worldwide, and Lime Rock Resources, acquirers and operators of oil and gas properties in the United States. Lime Rock has invested in 89 companies to date and has offices in Westport, Houston, and London.

Emerging Growth Company Status

We are an "emerging growth company" as defined in the Jumpstart Our Business Startups Act (the "JOBS Act"). For as long as we are an emerging growth company, unlike other public companies that are not emerging growth companies under the JOBS Act, we are not required to:

•: provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;
•: provide more than two years of audited financial statements and related management's discussion and analysis of financial condition and results of operations nor more than two years of selected financial data;
•: comply with any new requirements adopted by the Public Company Accounting Oversight Board (the "PCAOB") requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;
•: provide certain disclosure regarding executive compensation required of larger public companies or hold shareholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"); or
•: obtain shareholder approval of any golden parachute payments not previously approved.

We will cease to be an "emerging growth company" upon the earliest of:

•: the last day of the fiscal year in which we have $1.0 billion or more in annual revenues;
•: the date on which we become a "large accelerated filer" (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

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•: the date on which we issue more than $1.0 billion of non-convertible debt over a three-year period; or
•: the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the "Securities Act") for complying with new or revised accounting standards, but we have irrevocably opted out of the extended transition period and, as a result, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

Corporate Information

Our principal executive offices are located at 116 Inverness Drive East, Suite 107, Englewood, Colorado 80112, and our telephone number at that address is (303) 386-8600. Our website is located at www.vantageenergy.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on, or otherwise accessible through, our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

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The Offering


Common stock offered by us		shares (or shares, if the underwriters exercise in full their option to purchase additional shares).
Common stock to be outstanding after the offering		shares (or shares, if the underwriters exercise in full their option to purchase additional shares).
Option to purchase additional shares		We have granted the underwriters a 30 day option to purchase up to an aggregate of additional shares of our common stock.
Use of proceeds		We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us (or approximately $ million, if the underwriters exercise in full their option to purchase additional shares) after deducting underwriting discounts and commissions and estimated offering expenses payable by us.
		We intend to use the net proceeds from this offering, together with cash on hand and borrowings under our new revolving credit facility, to repay and retire the Vantage I revolving credit facility, the Vantage I second lien term loan and the Vantage II revolving credit facility. We intend to use the remaining net proceeds for general corporate purposes, including funding our drilling program and expanding our midstream infrastructure. Please see "Use of Proceeds".
Dividend policy		We do not anticipate paying any cash dividends on our common stock. In addition, our new revolving credit facility will place certain restrictions on our ability to pay cash dividends.
Directed share program		At our request, the underwriters have reserved for sale at the initial public offering price up to % of the shares offered by this prospectus for our officers, directors, employees and certain other persons associated with us. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Please read "Underwriting".
Risk factors		You should carefully read and consider the information set forth under the heading "Risk Factors" and all other information set forth in this prospectus before deciding to invest in our common stock.
Listing and trading symbol		We have applied to list our common stock on the New York Stock Exchange (the "NYSE") under the symbol "VEI".

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The information above excludes shares of common stock reserved for issuance under our long-term incentive plan (the "LTIP") that we intend to adopt in connection with the completion of this offering.

In addition, it does not give effect to the grant of an aggregate of approximately shares of restricted stock (based on the midpoint of the price range set forth on the cover page of this prospectus) that our board of directors intends to make to certain of our directors, officers and employees in connection with the completion of this offering.

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Summary Historical Consolidated and Unaudited Pro Forma Financial Data

The following table shows summary historical consolidated financial data of our predecessor, and summary unaudited pro forma financial data for the periods and as of the dates indicated.

The summary historical consolidated financial data as of and for the years ended December 31, 2015 and 2014 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

The summary historical consolidated financial data as of and for the six months ended June 30, 2016 and 2015 were derived from the unaudited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The summary unaudited historical consolidated financial data has been prepared on a consistent basis with the audited consolidated financial statements of our predecessor. In the opinion of management, such summary unaudited historical consolidated interim financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors.

The summary unaudited pro forma statements of operations data for the year ended December 31, 2015 and the six months ended June 30, 2016 has been prepared to give pro forma effect to (i) the reorganization transactions described under "Corporate Reorganization" and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The summary unaudited pro forma balance sheet data has been prepared to give pro forma effect to those transactions as if they had been completed as of June 30, 2016. These data are subject to and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

You should read the following table in conjunction with "Use of Proceeds", "Management's Discussion and Analysis of Financial Condition and Results of Operations", "Corporate Reorganization", the historical consolidated financial statements of our predecessor and the unaudited pro forma financial statements included elsewhere in this prospectus. Among other

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things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.


	Predecessor												Vantage Energy Inc. Pro Forma

	Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30,			Year Ended December 31,

(in thousands, except per share data)	2016			2015			2015			2014			2016			2015

Statement of operations data:
Operating revenues:
Natural gas	$	46,829		$	40,375		$	65,252		$	43,622			$			$
Midstream revenues⁽¹⁾	2,895			2,524			4,054			2,990
Gain (loss) on commodity derivatives	(22,599		)	14,921			51,793			14,434

Total operating revenues	27,125			57,820			121,099			61,046
Operating expenses:
Production and ad valorem taxes⁽²⁾	1,025			512			1,911			1,723
Marketing and gathering	7,961			6,063			9,745			5,333
Lease operating and workover⁽³⁾	1,590			4,451			4,934			2,517
Midstream operating expenses	1,428			831			1,834			891
General and administrative⁽³⁾	4,336			5,487			7,308			5,423
Depreciation, depletion, amortization and accretion	19,490			23,357			39,698			18,302
Impairment of proved oil and gas properties	81,673			—			172,673			—

Total operating expenses	117,503			40,701			238,103			34,189

Operating (loss) income	(90,378		)	17,119			(117,004		)	26,857
Other income (expense)	3			(180		)	(180		)	—
Interest income, net	—			—			—			—
Interest expense, net of capitalized interest⁽⁴⁾	(5,264		)	(4,229		)	(8,778		)	(4,027		)

Income (loss) before income taxes	(5,261		)	(4,409		)	(125,962		)	22,830
Income tax expense (benefit)	—			—			—			—

Net income (loss)	$	(95,639	)	$	12,710		$	(125,962	)	$	22,830			$			$



Balance sheet data (at period end):
Cash	$	15,085		$	8,726		$	2,439		$	21,185			$			$
Total oil and gas properties, net	687,495			486,043			373,786			439,076
Total midstream system, net	59,764			56,458			59,970			53,116
Total assets	780,421			588,640			488,739			551,345
Total debt	244,993			225,087			247,041			197,663
Total members'/stockholders' capital	474,866			339,263			200,093			326,055
Net cash provided by (used in):
Operating activities	$	72,209		$	39,792		$	81,633		$	21,100			$			$
Investing activities	(427,740		)	(78,804		)	(148,852		)	(212,615		)
Financing activities	368,177			26,553			48,473			206,921
Other financial data (unaudited):
E&P Segment Adjusted EBITDA⁽⁵⁾	48,348			28,994			57,229			26,207				107,566			182,020
Midstream Segment Adjusted EBITDA⁽⁶⁾	11,195			6,345			14,056			5,317				22,393			28,112
Adjusted EBITDA⁽⁷⁾	$	59,007		$	40,656		$	69,983		$	31,660			$	128,872		$	207,528
Earnings (loss) per share — basic
Earnings (loss) per share — diluted

(1): Midstream revenues are net of gathering, compression and water fees paid by Vantage II for historical periods and by Vantage I and Vantage II on a pro forma basis. See "Management's Discussion and Analysis of Financial Condition and Results of Operation — Sources of Revenues — Gathering Revenues".

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(2): Production and ad valorem taxes include expenses recorded for Pennsylvania impact fees, which are annual fees imposed by the state of Pennsylvania on natural gas and oil operators in Pennsylvania for each well drilled for a period of fifteen years.
(3): Lease operating and workover expense includes Council of Petroleum Accountants Society ("COPAS") overhead booked as a reclassification from general and administrative expense on our operated properties and any COPAS charged to us by other operators on our non-operated properties. On a pro forma basis for the six months ended June 30, 2016 and for the year ended December 31, 2015, we recorded allocated COPAS overhead charges of $1.1 million and $2.1 million, respectively. General and administrative expenses are net of overhead recorded to lease operating and workover expenses and the capitalization of certain internal costs. On a pro forma basis for the six months ended June 30, 2016 and the year ended December 31, 2015, we recorded $7.6 million and $13.3 million, respectively, of general and administrative expense, net of allocated COPAS overhead of $1.1 million and $2.1 million, respectively and capitalized general and administrative expenses of $5.1 million and $9.8 million, respectively.
(4): On a pro forma basis for the six months ended June 30, 2016 and for the year ended December 31, 2015, we recorded capitalized interest of $2.9 million and $5.8 million, respectively.
(5): We define E&P Segment Adjusted EBITDA as total revenues from our E&P Segment (including net cash from settlement from commodity derivatives) less E&P Segment operating costs and allocated general and administrative expenses. E&P Segment Adjusted EBITDA for Vantage I was $59.2 million and $124.8 million for the six months ended June 30, 2016 and the year ended December 31, 2015, respectively. Pro forma E&P Segment Adjusted EBITDA represents the sum of the E&P Segment Adjusted EBITDA for our predecessor and Vantage I for such period. See Note 11 and Note 13 to the audited consolidated financial statements of our predecessor and Vantage I, respectively, included elsewhere in this prospectus for a discussion of our segment reporting.
(6): We define Midstream Segment Adjusted EBITDA as total revenues from our Midstream Segment less Midstream Segment operating costs and allocated general and administrative expenses. Midstream Segment Adjusted EBITDA for Vantage I was $11.2 million and $14.1 million for the six months ended June 30, 2016 and the year ended December 31, 2015, respectively. Pro forma Midstream Segment Adjusted EBITDA represents the sum of the Midstream Segment Adjusted EBITDA for our predecessor and Vantage I for such period. See Note 11 and Note 13 to the audited consolidated financial statements of our predecessor and Vantage I, respectively, included elsewhere in this prospectus for a discussion of our segment reporting.
(7): Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss), please see "— Non-GAAP Financial Measure" below.

Non-GAAP Financial Measure

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDA as net income (loss) before interest, income taxes, impairment of proved oil and gas properties, depreciation, depletion, amortization and accretion and derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments. Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles ("GAAP").

Management believes Adjusted EBITDA is a commonly used metric and is useful because it allows investors a consistent method of evaluating our operating performance and compare the results of our operations from period to period and against our peers without regard to our accounting methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of

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depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).


	Predecessor												Vantage I								Vantage Energy Inc. Pro Forma

	Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30,				Year Ended December 31,				Six Months Ended June 30,		Year Ended December 31,

(in thousands)	2016			2015			2015			2014			2016				2015				2016		2015

Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	(95,639	)	$	12,710		$	(125,962	)	$	22,830			$	(181,568	)		$	(292,938	)		$		$
Interest income, net	—			—			—			—				—				—
Interest expense, net of capitalized interest	5,264			4,229			8,778			4,027				12,371				22,058
Depreciation, depletion, amortization and accretion	19,490			23,357			39,698			18,302				26,476				50,162
Impairment of proved oil & gas properties	81,673			—			172,673			—				155,994				344,401
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives(1)	48,219			(4,957		)	(25,204		)	(13,499		)		56,592				13,862
Income tax expense (benefit)	—			—			—			—				—				—

Adjusted EBITDA	$	59,007		$	35,339		$	69,983		$	31,660			$	69,865			$	137,545			$		$

(1): The adjustments for the total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges.

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Summary Reserve, Production and Operating Data

Summary Reserve Data

The following table summarizes estimated proved reserves as of December 31, 2015 based on reports prepared by Netherland, Sewell & Associates, Inc. ("NSAI") and Wright & Company, our independent reserve engineers. All of these reserve estimates were prepared in accordance with the SEC's rules regarding reserve reporting that are currently in effect.

The information in the following table does not give any effect to or reflect our commodity hedges. Please see "Business — Our Operations — Reserve Data" for more information about our reserves.


	At December 31, 2015⁽¹⁾⁽²⁾

Estimated proved reserves:
Natural gas (Bcf)		1,755
NGLs (MMBbl)		23.8
Oil (MMBbl)		1.2
Total equivalent proved reserves (Bcfe)		1,905
Total equivalent proved developed reserves (Bcfe)		768
Percent proved developed		40.3	%
Total equivalent proved undeveloped reserves (Bcfe)		1,137

(1): Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. As of December 31, 2015, the SEC Price Deck was $2.59/Mcf for natural gas, $16.22/Bbl for NGLs and $50.28/Bbl for oil, representing the prices for Henry Hub natural gas, Mont Belvieu NGLs, and WTI oil, respectively. In determining our reserves, the SEC Price Deck was adjusted by field or lease for quality, transportation fees, regional price differentials and other factors affecting the price received at the wellhead. The corresponding natural gas basis prices proximate to our operating areas were $1.39/Mcf and $2.47/Mcf for Dominion South Point and WAHA, respectively. There were no proved reserves associated with our Utica Shale acreage as of December 31, 2015.
(2): The reserve data presented is that of Vantage II and Vantage I on a combined basis as of December 31, 2015, assuming a 30-year reserve life.

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Production and Operating Data

The following table sets forth information regarding production, revenues and realized prices, and production costs and other operating data for the six months ended June 30, 2016 and the year ended December 31, 2015. For additional information on price calculations, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations".


	Six Months Ended June 30, 2016⁽¹⁾			Year Ended December 31, 2015⁽¹⁾

Production data:
Natural gas (MMcf)		66,986			82,391
NGLs (MBbl)		525			796
Oil (MBbl)		43			74

Total combined production (MMcfe)		70,394			87,612
Average net daily combined production (MMcfe/d)		387			240
Average sales prices:
Natural gas (per Mcf)		$	1.35		$	1.68
NGLs (per Bbl)		11.09			10.45
Oil (per Bbl)		34.09			41.00
Combined average sales prices before effects of cash settled derivatives (per Mcfe)⁽²⁾		1.39			1.71
Combined average sales prices after effects of cash settled derivatives (per Mcfe)⁽¹⁾		2.26			2.97
Average costs per Mcfe:
Lease operating and workover expenses		$	0.13		$	0.26
Marketing and gathering		0.20			0.17
Production and ad valorem taxes		0.06			0.08
Depreciation, depletion, amortization and accretion		0.65			1.03
General and administrative		0.11			0.15
Midstream Segment operating data⁽³⁾:
Gas gathering throughput (Mcf/d)		265,538			176,324
Gas gathering and compression revenues		$	25,535		$	31,512
Gas gathering and compression expenses⁽⁴⁾		2,854			3,676
Water volumes (Bbls/d)		12,054			9,928
Water revenues		$	7,889		$	10,974
Water system expenses⁽⁴⁾		6,913			8,370

(1): The operational data presented is that of Vantage II and Vantage I on a combined basis for the periods presented.
(2): Average sales prices shown reflect both the before and after effects of our cash settled derivatives. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate them as hedges.
(3): Midstream Segment operating revenues and expenses are presented prior to elimination entries. For more information on Midstream Segment operating revenues and expenses, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations — Sources of Revenues" and "Management's Discussion and Analysis of Financial Condition and Results of Operations — Principal Components of our Cost Structure".
(4): Gas gathering and compression expenses and water system expenses exclude allocated general and administrative expense.

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RISK FACTORS

Investing in our common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under "Cautionary Statement Regarding Forward-Looking Statements", and the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

Natural gas, NGLs and oil prices are volatile. A further reduction or sustained decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our natural gas production heavily influence, and to the extent we produce oil and NGLs in the future, the prices we receive for oil and NGLs production will heavily influence, our revenue, operating results profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•: worldwide and regional economic conditions impacting the global supply of and demand for natural gas, NGLs and oil;
•: the price and quantity of imports of foreign natural gas, including liquefied natural gas;
•: political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
•: the level of global exploration and production;
•: the level of global inventories;
•: prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;
•: increased associated natural gas production resulting from higher oil prices and the related increase in oil production;
•: the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
•: localized and global supply and demand fundamentals and transportation availability;
•: the actions of the Organization of the Petroleum Exporting Countries;
•: weather conditions and other natural disasters;
•: technological advances affecting energy consumption;
•: speculative trading in natural gas and crude oil derivative contracts;
•: increased end-user conservation;

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•: the price and availability of alternative fuels; and
•: domestic, local and foreign governmental regulation and taxes.

In late 2014, global energy commodity prices declined precipitously as a result of several factors, including an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions of the U.S. during winter months, and strong competition among oil producing countries for market share. These events continued throughout 2015 and the first half of 2016 and, along with slower economic growth in China, have led to a further decline in commodity prices. Spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.70 per MMBtu for a brief period in March 2016.

In addition, substantially all of our natural gas production is sold to purchasers under contracts with market-based prices. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differentials, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors.

If commodity prices decrease further or we experience negative basis differentials, our cash flows and borrowing ability will be reduced. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically. Additionally, a significant portion of our development and exploration projects could become uneconomic and require us to re-evaluate or postpone such drilling. This may result in our having to make further downward adjustments to our estimated proved reserves. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our estimated proved reserves. As a result, a further reduction or sustained decline in commodity prices or negative basis differentials in the areas in which we operate may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.

The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas reserves. See "Prospectus Summary — Capital Program". We have not allocated any capital spending to properties other than our primary Marcellus, Upper Devonian and Barnett Shale operations. Our capital budget excludes acquisitions, other than leasehold acquisitions.

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction or sustained decline in natural gas prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through available capacity under our new revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of

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additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables, including:

•: our proved reserves;
•: the level of hydrocarbons we are able to produce from existing wells;
•: the prices at which our production is sold;
•: our ability to acquire, locate and produce new reserves;
•: the levels of our operating expenses; and
•: our ability to borrow under our new revolving credit facility.

If our revenues or the borrowing base under our new revolving credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our planned capital budget or operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available capacity under our new revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

In addition to our primary operations in the Appalachian Basin and the Barnett Shale, we hold additional acreage in the Uinta and Piceance plays in Utah and Colorado, respectively. Due to the limited operational history with horizontal development, each of the Upper Devonian Shale, Utica Shale, Uinta and Piceance plays may be considered a new or emerging play.

Drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited production history and since we have limited experience drilling in these plays, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. We cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

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Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, the following:

•: effectively controlling the level of pressure flowing from particular wells;
•: landing our wellbore in the desired drilling zone;
•: staying in the desired drilling zone while drilling horizontally through the formation;
•: running our casing the entire length of the wellbore; and
•: being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells include, but are not limited to, the following:

•: the ability to fracture stimulate the planned number of stages;
•: the ability to run tools the entire length of the wellbore during completion operations; and
•: the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Drilling for and producing natural gas are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production, that we will not recover all or any portion of our investment in such wells or that various characteristics of the well will cause us to plug or abandon the well prior to producing in commercially viable quantities.

Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, please see "— Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves". In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

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Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•: reductions or sustained declines in natural gas prices;
•: delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, discharge of greenhouse gases and limitations on hydraulic fracturing;
•: pressure or irregularities in geological formations;
•: shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
•: equipment failures, accidents or other unexpected operational events;
•: lack of available gathering facilities or delays in construction of gathering facilities;
•: lack of available capacity on interconnecting transmission pipelines or the failure of our product to meet quality specifications for such pipeline;
•: lack of available processing facilities on economic terms;
•: adverse weather conditions, such as blizzards and ice storms;
•: issues related to compliance with environmental regulations;
•: environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
•: limited availability of financing at acceptable terms;
•: title problems; and
•: limitations in the market for natural gas.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including the new revolving credit facility that we expect to enter into in connection with the completion of this offering and the $100 million Vantage II second lien term loan, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness

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will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our new revolving credit facility and the Vantage II second lien term loan will restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

In the future, we may not be able to access adequate funding under our new revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender's portion. The lenders will be able to unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the facility. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Substantially all of our producing properties are located in the Appalachian Basin and Barnett Shale, making us vulnerable to risks associated with operating in only two geographic areas.

Substantially all of our producing properties are located in the Appalachian Basin and in the Barnett Shale. As a result of this geographic concentration, an adverse development in the oil and natural gas business in our operating areas could have a greater impact on our financial condition and results of operations than if we were more geographically diverse. Due to the concentrated nature of our properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations. For example, third parties may engage in subsurface mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling or adversely impact our midstream activities or those on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins, the plugging and abandonment of any of our wells or the repair of our midstream facilities. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, can cause delays

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or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations.

Insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.

The Appalachian Basin natural gas business environment has been characterized by periods in which production has surpassed local takeaway capacity, sometimes resulting in curtailment of production or substantial discounts in the price received by producers. Although additional Appalachian Basin takeaway capacity has been added in recent years, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by accelerated drilling in the area in the short term. Should production growth in the Appalachian Basin continue to outpace the increases in takeaway capacity, or if we are unable to secure firm takeaway capacity to accommodate our growing production, it could result in substantial discounts in the price we receive for our production, may limit our ability to market our production and could have a material adverse effect on our financial condition and results of operations. Moreover, if there is an extended interruption of access to or service from our or third-party midstream infrastructure for any reason, including cyber-attacks on such midstream infrastructure or service interruptions due to natural gas quality, we may experience these same adverse consequences.

Our investment in midstream infrastructure is intended to address a lack of capacity on, and access to, existing gathering pipelines in the Appalachian Basin as well as curtailments on such pipelines. Building and operating our midstream infrastructure involves significant risks, including those related to timing, cost overruns and operational efficiency. These risks can be affected by the availability of capital, materials and qualified personnel, as well as weather conditions, commodity price volatility, delays in obtaining permits and other government approvals, title and property access problems, geology, compliance by third parties with their contractual obligations to us and other factors.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

The Vantage II second lien term loan contains, and our new revolving credit facility will contain, a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

•: sell assets;
•: make loans to others;
•: make investments;
•: enter into mergers;
•: make certain payments;
•: hedge future production or interest rates;
•: incur liens;
•: engage in certain other transactions without the prior consent of the lenders; and
•: pay dividends.

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In addition, these debt agreements require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants impose on us. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations — Pro Forma Capital Resources and Liquidity — Debt Agreements — New Revolving Credit Facility" and "— Vantage II Second Lien Term Loan".

Any significant reduction in our borrowing base under our new revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our new revolving credit facility that we expect to enter into in connection with the completion of this offering will limit the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the natural gas and oil properties securing our loan. The lenders will be able to unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facilities. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas and oil properties as additional collateral after applicable grace periods. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our revolving credit facilities.

If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be an event of default under the terms of such agreements, which could result in an acceleration of repayment.

A breach of any covenant in any of our agreements governing our indebtedness would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the relevant facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements, which would have a material adverse effect on us. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. As of December 31, 2015, Vantage II and Vantage I were not in compliance with the minimum current ratio covenant under their revolving credit facilities but obtained a waiver of compliance from the lenders and were compliant with their financial covenants as of June 30, 2016. There is, however, no assurance that we will be successful in obtaining a waiver or amendment if we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness in the future.

Should we no longer be able to hedge at pricing we view as attractive, it could have a material adverse effect on our financial condition. Additionally, if development drilling costs increase significantly in the future, our hedged revenues may not be sufficient to cover our costs. Finally, in certain circumstances we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant.

In the past, we have received significant benefit from these hedge positions. For example, for the year ended December 31, 2015 we received approximately $110.0 million in revenues pursuant to our hedges, which represented approximately 39.2% of our total revenues for such periods. If we

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are unable to enter into new hedge contracts in the future at favorable pricing, our financial condition and results of operations could be materially adversely affected. Additionally, to the extent our development drilling costs are not fixed under contract and increase significantly in the future, our hedged revenues may not be sufficient to cover the increased development drilling costs as well as our operating costs.

As of July 31, 2016, we had entered into hedging contracts through 2019 covering a total of approximately 219 TBtu of our projected natural gas, NGLs and oil production at a weighted average price of $3.04 per MMBtu. For the period from January 1, 2017 to December 31, 2017, we have hedged approximately 2.26 Bcfe of our projected natural gas, NGLs and oil production at a weighted average price of $2.43 per MMBtu. If we have to purchase additional commodities on the open market or post cash collateral to meet obligations under such arrangements, our cash otherwise available for use in our operations would be reduced.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, production and ad valorem taxes and availability of funds.

Actual future production, natural gas, oil and NGLs prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, changes in existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas, oil and NGLs reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Most of our producing wells have been operational for less than three years and estimated reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion technique. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Our Effective Horizontal Acreage is based on our and other operators' current drilling results and our interpretation of available geologic and engineering data and therefore is an inexact estimate subject to various uncertainties.

Our Effective Horizontal Acreage is equal to what we believe to be our combined horizontal acreage position that is prospective for hydrocarbon production across our target formations underneath our total acreage of 258,734 net acres. Our belief is based upon our evaluation of our initial horizontal drilling results and results publicly released by other operators in our area to date, combined with our interpretation of available geologic and engineering data. Although we believe this acreage metric more accurately conveys our horizontal drilling opportunities in our target formations, and we believe our analysis of engineering, geological, geochemical and seismic data is based on industry standards, our calculation of our Effective Horizontal Acreage is an inexact estimate. We cannot assure you that all or any portion of our Effective Horizontal Acreage is prospective for our target formations, that any portion of our Effective Horizontal Acreage will ever be drilled or that, if drilled, will result in commercially productive wells.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our identified drilling locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our identified drilling locations are made up of drillable and estimated locations. Drillable locations are mapped locations that our reserve engineers have deemed to have a high likelihood of being drilled or are currently in development but have not yet commenced production. Drillable locations are subject to change, and their determination is based on many of the same assumptions and projections as with determining our reserve estimates. Estimated locations are calculated assuming 115 acre spacing for the Marcellus Shale. Our reserve engineers have deemed further de-risking of our Upper Devonian and Utica Shale acreage is required before including estimated well locations on this acreage in our identified drilling locations. Estimated locations are not mapped locations and are highly dependent on the interpretations of available technical data and assumptions that we use in determining our drillable locations. As a result, changes in our determination of drillable locations may have an effect on our calculation of estimated locations. For example, changes to our well spacing assumptions with respect to our drillable locations could have a significant impact on our estimated locations.

Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.

As of June 30, 2016, we had 1,361 identified drilling locations. As a result of the limitations described above, we may be unable to drill many of our identified drilling locations. In addition, we

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will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified drilling locations, please see "Business — Our Operations — Reserve Data — Determination of Identified Drilling Locations".

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2015, 60% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 1,137.4 Bcfe of estimated proved undeveloped reserves as of that date will require an estimated $575.2 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on our oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of June 30, 2016, approximately 66%, 93% and 17% of our net acreage was held in the Appalachian Basin, Barnett Shale and other areas, respectively, please see "Business — Our Operations — Undeveloped Acreage Expirations". The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Moreover, many of our leases require lessor consent to unitize, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. We cannot assure you that we will have the liquidity to deploy rigs when needed, or that commodity prices will warrant operating such a drilling program. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2015, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and

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natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

•: actual prices we receive for oil and natural gas;
•: actual cost of development and production expenditures;
•: the amount and timing of actual production; and
•: changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a limited liability company treated as a partnership for U.S. federal income tax purposes, our predecessor was not subject to federal taxation. Accordingly, our standardized measure does not provide for federal corporate income taxes because taxable income was passed through to the predecessor members. As a corporation, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus which could have a material effect on the value of our reserves.

We may incur losses as a result of title defects in the properties in which we invest.

Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease's oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly

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dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of July 31, 2016, we had entered into hedging contracts through 2019 covering a total of approximately 219 TBtu of our projected natural gas, NGLs and oil production at a weighted average price of $3.04 per MMBtu. For the period from January 1, 2017 to December 31, 2017, we have hedged approximately 2.26 Bcfe of our projected natural gas, NGLs and oil production at a weighted average price of $2.43 per MMBtu. Accordingly, earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

•: production is less than the volume covered by the derivative instruments;
•: the counterparty to the derivative instrument defaults on its contractual obligations;
•: there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
•: there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. As of June 30, 2016, the estimated fair value of our commodity derivative contracts was a liability of approximately $9.5 million. Any default by the counterparty to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.

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In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, NGLs and oil which could also have an adverse effect on our financial condition. If natural gas or oil prices upon settlement of our derivative contracts exceed the price at which we have hedged our commodities, we will be obligated to make cash payments to our hedge counterparties, which could, in certain circumstances, be significant.

The inability of our significant customers or working interest holders to meet their obligations to us may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our combined principal exposures to credit risk are through joint interest receivables ($4.4 million at June 30, 2016) and the sale of our natural gas production ($24.1 million in receivables at June 30, 2016), which we primarily market to four natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with several significant customers. We do not require our customers to post collateral. The inability or failure of our significant customers or working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency ("EPA"), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons, or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from

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the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. For example, the EPA has designated energy extraction as one of six national enforcement initiatives for FY 2014-2016 and FY 2017-2019, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. Also, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.

In addition, EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. In May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act; the EPA has indicated that it intends to publish a final notice of proposed rulemaking in December 2016. Further, the EPA finalized regulations under the federal Clean Water Act ("CWA") in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. Also, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized in 2016 after a public comment period and a formal review by the EPA's Science Advisory Board. In addition, the federal Bureau of Land Management finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands; however, the U.S. District Court of Wyoming struck down this rule in June 2016. An appeal of this decision is pending.

Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Pennsylvania, Texas,

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Colorado and Utah (where we conduct operations) have adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, the Pennsylvania Supreme Court has limited the state's ability to limit such ordinances at and strengthened the ability of municipalities to enact local ordinances regulating drilling activities. There are also numerous ballot measures being considered in Colorado, including measures granting greater autonomy to local governments to impose setback requirements for oil and gas facilities or ban certain businesses from operating in their jurisdictions. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In 2014, Texas adopted new oil and gas permit rules for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the state to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Pursuant to the authority under the Natural Gas Pipeline Safety Act ("NGPSA") and the Hazardous Liquid Pipeline Safety Act ("HLPSA"), as amended by the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 ("2011 Pipeline Safety Act"), the Pipeline and Hazardous Materials Safety Administration ("PHMSA") has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture could affect "high consequence areas", which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:

•: perform ongoing assessments of pipeline integrity;
•: identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•: improve data collection, integration and analysis;
•: repair and remediate the pipeline as necessary; and
•: implement preventive and mitigating actions.

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In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of pipeline integrity testing, but the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the safe and reliable operation of our pipelines.

The 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. Changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators.

For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Also, in October 2015, PHMSA proposed new regulations for hazardous liquid pipelines that would significantly extend and expand the reach of certain PHMSA integrity management requirements (i.e., periodic assessments, repairs and leak detection), regardless of the pipeline's proximity to a high consequence area. The proposal also requires new reporting requirements for certain unregulated pipelines, including all gathering lines. More recently, in March 2016, pursuant to one of the requirements in 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA, rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Moreover, effective October 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations that occur after January 3, 2012 to $200,000 per violation per day and up to $2 million for a related series of violations. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

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Oil and natural gas producers' operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water for exploration and production activities and the disposal of produced water may impact our operations.

Water is an essential component of oil and natural gas production during the drilling and, in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations.

Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Specific to Pennsylvania, sending wastewater to publicly owned treatment works requires certain levels of pretreatment that may effectively prohibit this method as a disposal option, leaving disposal via saltwater disposal injection well as our primary option. Our continued ability to use injection wells as a disposal option on economic terms not only will depend on federal or state regulations but also on the cost and availability of wells with sufficient storage capacities. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and any inability to secure transportation and access to disposal wells with sufficient capacity to accept all our produced water on economic terms may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

We are subject to risks associated with climate change.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards that will be established on a case-by-case basis. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. Recently, in December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule

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includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. The BLM has also proposed rules to reduce methane emissions from venting, flaring, and leaking on public lands. As a result of this continued regulatory focus, future federal GHG regulations of the oil and gas industry remain a possibility.

Several states, including Colorado and Pennsylvania, are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions leakage. These rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us to incur increased operating costs. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services and adversely affect our financial position and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by our customers or otherwise cause us to incur significant costs in preparing for or responding to those effects.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:

•: environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
•: abnormally pressured formations;
•: mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
•: fires, explosions and ruptures of pipelines;
•: personal injuries and death;
•: natural disasters; and
•: terrorist attacks targeting natural gas and oil related facilities and infrastructure.

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Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

•: injury or loss of life;
•: damage to and destruction of property, natural resources and equipment;
•: pollution and other environmental damage;
•: regulatory investigations and penalties;
•: suspension of our operations; and
•: repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the "occurrence" to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.

Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or

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completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

•: unexpected drilling conditions;
•: title problems;
•: pressure or lost circulation in formations;
•: equipment failure or accidents;
•: adverse weather conditions;
•: compliance with environmental and other governmental or contractual requirements; and
•: increase in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our new revolving credit facility will impose certain limitations on our ability to enter into mergers or combination transactions. Our new revolving credit facility will also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

We depend upon a limited number of significant purchasers for the sale of most of our production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the hydrocarbons we produce.

The availability of a ready market for any hydrocarbons we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold in interstate commerce. In addition, we

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depend upon a limited number of significant purchasers for the sale of most of our production, and our contracts with those customers typically are on a month-to-month basis. The loss of these customers could adversely affect our revenues and have a material and adverse effect on our financial condition and results of operations. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production.

Market conditions or the availability and capacity of gathering systems, transportation and processing facilities may hinder our access to natural gas, NGLs or oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas, NGLs or oil gathering, transportation or processing arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the operation, availability, proximity, capacity and expansion of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGLs or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. Our access to transportation options, including trucks owned by third parties, may also be affected by U.S. federal and state regulation of natural gas, NGLs and oil production and transportation. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to gather, process and deliver the products to market. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our one-rig drilling program in the Marcellus Shale; however, certain of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938 ("NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC"), as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 ("EPAct 2005"), FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Competition in the natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain

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qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

We are susceptible to the potential difficulties associated with rapid growth and expansion.

We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

•: increased responsibilities for our executive level personnel;
•: increased administrative burden;
•: increased capital requirements; and
•: increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future.

Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global energy capital markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

•: recoverable reserves;
•: future natural gas, NGLs or oil prices and their applicable differentials;
•: operating costs; and
•: potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized some regulations, including critical rulemakings on the definition of "swap", "swap dealer", and "major swap participant", others remain to be finalized and it is not possible at this time to predict when this will be accomplished.

The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC's initial position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from the mandatory clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce our cash

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available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an "oil fee" of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

Pennsylvania imposes an annual natural gas impact fee on natural gas and oil operators in Pennsylvania for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed.

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Ohio has previously considered, and its legislature continues to consider, proposals to increase the current severance tax imposed on natural gas or oil in Ohio. There is currently no severance tax imposed on natural gas or oil in Pennsylvania. However, it is possible that each of these states could propose and implement a new or increased severance tax in the coming years, which would negatively affect our future cash flows and financial condition.

Our method of accounting for investments in oil and natural gas properties may result in ceiling test write-downs, which could negatively impact our results of operations.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are generally accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per MMcfe of production for our predecessor and Vantage I was $0.88 and $0.99 for 2015, respectively, and $1.13 and $1.24 for 2014, respectively. Total depletion expense for oil and natural gas properties for our predecessor and Vantage I was $36.3 million and $45.7 million for 2015, respectively, and $16.5 million and $35.1 million for 2014, respectively. The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization, accretion and impairment exceed the discounted future net revenues of proved reserves plus the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects, the excess capitalized costs are charged to expense.

Accounting rules require that we review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. Our predecessor and Vantage I incurred approximately $172.7 million and $344.4 million of impairment charges during 2015, respectively, and $81.7 million and $156.0 million of impairment charges during the six months ended June 30, 2016, respectively. Recently, commodity prices have declined significantly and have remained depressed thus far in 2016. For example, the NYMEX Henry Hub spot market price declined from a high of approximately $6.00 per MMBtu in 2014 to below $1.70 per MMBtu in March 2016. Natural gas and oil prices have remained depressed thus far in 2016, and lower commodity prices in the future could result in further impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates" for a more detailed description of our method of accounting.

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Risks Related to the Offering and our Common Stock

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

•: institute a more comprehensive compliance function;
•: comply with rules promulgated by the NYSE;
•: continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
•: establish new internal policies, such as those relating to insider trading; and
•: involve and retain to a greater degree outside counsel and accountants in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2016, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an "emerging growth company" within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2022. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

There is no existing market for our common stock, and we do not know if one will develop to provide you with adequate liquidity to sell our common stock at prices equal to or greater than the price you paid in this offering.

Prior to this offering, there has not been a public market for our common stock. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the stock exchange on which we list our common stock or otherwise or how liquid that market might become. If an active trading market does not develop, you may have

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difficulty selling any of our common stock that you buy. The initial public offering price for the common stock was determined by negotiations between us and the representatives of the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our common stock at prices equal to or greater than the price you paid in this offering, or at all.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors' purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price was determined by negotiations between us and representatives of the underwriters, based on numerous factors which we discuss in "Underwriting", and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The following factors could affect our stock price:

•: our operating and financial performance and drilling locations, including reserve estimates;
•: the public reaction to our press releases, our other public announcements and our filings with the SEC;
•: strategic actions by our competitors;
•: our failure to meet revenue, reserves, production or earnings estimates by research analysts or other investors;
•: changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;
•: speculation in the press or investment community;
•: the failure of research analysts to cover our common stock;
•: sales of our common stock by us or other stockholders, or the perception that such sales may occur;
•: changes in accounting principles, policies, guidance, interpretations or standards;
•: additions or departures of key management personnel;
•: actions by our stockholders;
•: general market conditions, including fluctuations in commodity prices;
•: domestic and international economic, legal and regulatory factors unrelated to our performance; and
•: the realization of any risks describes under this "Risk Factors" section.

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The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company's securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management's attention and resources and harm our business, operating results and financial condition.

Vantage Investment I, Vantage Investment II and the Management Members will collectively hold a substantial majority of our common stock.

Immediately following the completion of this offering, Vantage Investment I, Vantage Investment II and the Management Members will hold approximately %, % and %, respectively, of our common stock. Vantage Investment I and Vantage Investment II (and indirectly, our Sponsors) will have the collective voting power to elect all of the members of our board of directors and thereby control our management and affairs. In addition, they will be able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company. The existence of significant stockholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as our Sponsors continue to control a significant amount of our common stock, they will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of our Sponsors may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

Conflicts of interest could arise in the future between us, on the one hand, and our Sponsors and their affiliates, including their portfolio companies, and our other Existing Owners, on the other hand, concerning among other things, potential competitive business activities or business opportunities.

Our Sponsors are each families of private equity investment funds in the business of making investments in entities primarily in the U.S. energy industry. As a result, our Sponsors may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Our Sponsors may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, our Sponsors and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours.

Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.

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Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•: limitations on the removal of directors;
•: limitations on the ability of our stockholders to call special meetings;
•: establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;
•: the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock (or a majority of the voting power of all outstanding shares of capital stock if the Sponsors beneficially own at least 50% of the voting power of all such outstanding shares) be obtained to amend our amended and restated bylaws, to remove directors or to amend our certificate of incorporation;
•: providing that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws; and
•: establishing advance notice and certain information requirements for nominations for election to our Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

Investors in this offering will experience immediate and substantial dilution of $ per share.

Based on an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2016 on a pro forma basis would be $ per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. Please see "Dilution".

We do not intend to pay dividends on our common stock, and our debt instruments place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our new revolving credit facility will place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

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Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we are selling in this offering and shares if the underwriters' option to purchase additional shares is fully exercised. Following the completion of this offering, assuming no exercise of the underwriters' option to purchase additional shares, Vantage Investment I, Vantage Investment II and the Management Members will collectively own shares of our common stock, or approximately % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in "Underwriting", but may be sold into the market in the future. Vantage Investment I and Vantage Investment II will be party to a stockholders' agreement with us which will require us to effect the registration of their shares (and shares of certain of their affiliates) in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Please see "Shares Eligible for Future Sale" and "Certain Relationships and Related Party Transactions — Stockholders' Agreement".

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, Vantage Investment I, Vantage Investment II, and all of our directors and executive officers have entered into lock-up agreements with respect to their common stock, pursuant to which we and they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. Goldman, Sachs & Co., at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

We expect to be a "controlled company" within the meaning of the NYSE rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements.

Upon completion of this offering, Vantage Investment I and Vantage Investment II will collectively beneficially control a majority of the combined voting power of all classes of our

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outstanding voting stock. In connection with the completion of this offering, Vantage I and Vantage II will enter into a stockholders' agreement, pursuant to which they will agree to vote their shares of common stock in accordance with the stockholders' agreement, including as it relates to the election of directors. For additional information regarding the stockholders' agreement, please see "Certain Relationships and Related Party Transactions — Stockholders' Agreement". As a result, we expect to be a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

•: a majority of the board of directors consist of independent directors;
•: the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities;
•: the compensation committee be composed entirely of independent directors with a written charter addressing the committee's purpose and responsibilities; and
•: there be an annual performance evaluation of the nominating and governance and compensation committees.

These requirements will not apply to us as long as we remain a controlled company. Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. Please see "Management".

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

We are classified as an "emerging growth company" under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor's attestation report on management's assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor's report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our

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common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the "DGCL"), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. This choice of forum provision may limit a stockholder's ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes "forward-looking statements". All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words "could", "believe", "anticipate", "intend", "estimate", "expect", "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under "Risk Factors". These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

•: business strategy;
•: reserves;
•: financial strategy, liquidity and capital required for our development program;
•: realized natural gas, NGLs and oil prices;
•: timing and amount of future production of natural gas, NGLs and oil;
•: hedging strategy and results;
•: future drilling plans;
•: competition and government regulations;
•: pending legal or environmental matters;
•: marketing of natural gas, NGLs and oil;
•: leasehold or business acquisitions;
•: costs of developing our properties and conducting our gathering and other midstream operations;
•: expectations with respect to the cost of expansion of our midstream infrastructure and the expected timing of such expansion;
•: general economic conditions;
•: credit markets;
•: uncertainty regarding our future operating results; and
•: plans, objectives, expectations and intentions contained in this prospectus that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs and oil

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reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under "Risk Factors".

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, and NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

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USE OF PROCEEDS

We expect to receive approximately $ million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering, together with cash on hand and borrowings under our new revolving credit facility, to repay and retire the Vantage I revolving credit facility, the Vantage I second lien term loan and the Vantage II revolving credit facility. We intend to use the remaining net proceeds for general corporate purposes, including funding our drilling program and expanding our midstream infrastructure. In connection with the repayment of the term loan and credit facility borrowings, we expect to record a $ million earnings charge for the extinguishment of debt; however, this charge is not reflected in our pro forma financial statements included elsewhere in this prospectus.

The following table illustrates our anticipated use of the proceeds of this offering:


Sources of Funds (in millions)		Uses of Funds (in millions)
Gross proceeds from this offering	$	Repayment of Vantage I revolving credit facility	$
Cash on hand		Repayment of Vantage I second lien term loan
Borrowings under the new revolving credit facility		Repayment of Vantage II revolving credit facility
		General corporate purposes
		Underwriting discounts, fees and expenses

Total	$	Total	$

As of June 30, 2016, we had $270.0 million of outstanding borrowings under the Vantage I revolving credit facility. The Vantage I revolving credit facility matures on January 1, 2017 and bears interest at a variable rate, which was 3.96% per annum at June 30, 2016. As of June 30, 2016, we had $147.0 million of outstanding borrowings under the Vantage II revolving credit facility. The Vantage II revolving credit facility matures on January 1, 2017 and bears interest at a variable rate, which was 3.71% per annum at June 30, 2016.

The $200 million Vantage I second lien term loan matures on December 20, 2018 and bears interest at a variable rate, which was 8.5% per annum at June 30, 2016.

The outstanding borrowings under our revolving credit facilities and term loans were incurred to fund our development program. We may at any time borrow amounts under our new revolving credit facility, and we expect to do so to fund our development program.

A $1.00 increase or decrease in the assumed initial public offering price of $ per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $ million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase for any reason, we would use the additional net proceeds to reduce the amount we borrow under our new revolving credit facility or for general corporate purposes, including to fund a portion of our development program. If the proceeds decrease for any reason, then we would increase by a corresponding amount the amount of borrowings under our new revolving credit facility, but not to exceed the then in effect borrowing base.

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. Additionally, our new revolving credit facility will place certain restrictions on our ability to pay cash dividends.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2016:

•: on an actual basis for our predecessor;
•: on an as adjusted basis to give effect to the transactions described under "Corporate Reorganization"; and
•: on a pro forma basis to give further effect to (i) the sale of shares of our common stock by us in this offering at an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus) and the application of the net proceeds as set forth under "Use of Proceeds" and (ii) our entrance into and incurrence of borrowings under our new revolving credit facility.

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with, and is qualified in its entirety by reference to, "Use of Proceeds" and our predecessor's historical audited consolidated financial statements and the unaudited pro forma financial statements and the accompanying notes appearing elsewhere in this prospectus.


	As of June 30, 2016

	Actual			As Adjusted	Pro Forma

	(In thousands, except share counts and par value)
Cash and cash equivalents⁽¹⁾	$	15,085		$	$



Long-term debt, including current maturities, net of unamortized deferred financing costs:
Vantage I revolving credit facility⁽²⁾
Vantage II revolving credit facility⁽²⁾	146,239
Vantage I second lien term loan
Vantage II second lien term loan⁽³⁾	98,754
New revolving credit facility⁽¹⁾	—

Total indebtedness	$	244,993		$	$

Contingently redeemable Founders' units⁽⁴⁾	$	1,125		$	$
Members'/Stockholders' equity:
Members' equity	670,074
Preferred stock — $0.01 par value; no shares authorized, issued or outstanding, actual; shares authorized, no shares issued or outstanding, as adjusted and pro forma	—
Common stock — $0.01 par value; no shares authorized, issued or outstanding, actual; shares authorized, shares issued and outstanding, as adjusted; shares authorized, shares issued and outstanding, pro forma	—
Additional paid in capital⁽⁵⁾	—
Accumulated deficits	(195,208		)

Total Members'/Stockholders' equity	$	474,866		$	$

Total capitalization	$	720,984		$	$

(1): As of , 2016, we had combined cash and cash equivalents of $ million. We intend to use the net proceeds of this offering, together with $ million of borrowings under our new revolving credit facility and

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$ million of cash on hand, to repay the Vantage I revolving credit facility, the Vantage I second lien term loan and the Vantage II revolving credit facility. Please see "Use of Proceeds".

(2): As of June 30, 2016, the outstanding amount under the Vantage I and Vantage II revolving credit facilities totaled $417.0 million, and we had $53.9 million of aggregate undrawn borrowing capacity. After giving effect to the consummation of the reorganization transactions described under "Corporate Reorganization", our entrance into and incurrence of borrowings under our new revolving credit facility and the application of the net proceeds of this offering, we expect to have $ million of available borrowing capacity under our new revolving credit facility. As of June 30, 2016, $0.1 million of letters of credit were outstanding under our revolving credit facilities. The Vantage II revolving credit facility is presented net of $0.8 million of net unamortized debt issuance costs.
(3): Net of approximately $1.0 million of issue discount and $0.3 million of debt issuance costs, which will be amortized over the term of the loan.
(4): Please see Note 9 to the audited consolidated financial statements of each of our predecessor and Vantage I included elsewhere in this prospectus for a description of the contingently redeemable Founders' units.
(5): In connection with our corporate reorganization, we expect to recognize non-cash stock compensation expense of approximately $ million at the time of the offering. The stock compensation expense recognized in the statement of operations will be offset by capital contributions from Vantage Investment II; therefore, the stock compensation charge will have no effect on total equity. The estimated stock compensation charge that we will recognize at the time of the offering is not reflected in the pro forma amounts as the charge is considered non-recurring. See "Management's Discussion and Analysis of Financial Condition and Results of Operations — Corporate Reorganization".

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DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of June 30, 2016, after giving effect to the transactions described under "Corporate Reorganization", was $ , or $ per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering after giving effect to our corporate reorganization. Assuming an initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus), after giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as June 30, 2016 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $ per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:


Initial public offering price per share		$
Pro forma net tangible book value per share as of June 30, 2016 (after giving effect to our corporate reorganization)	$
Increase per share attributable to new investors in this offering

As adjusted pro forma net tangible book value per share after giving effect to our corporate reorganization and this offering

Dilution in pro forma net tangible book value per share to new investors in this offering		$

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $ and increase (decrease) the dilution to new investors in this offering by $ per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. The following table summarizes, on an adjusted pro forma basis as of June 30, 2016, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at our initial public offering price of $ per share, calculated before deduction of estimated underwriting discounts and commissions:

Total Consideration

Average

Shares Acquired

Amount

Price Per

Number

Percent

(in thousands)

Percent

Existing owners

New investors in this offering

Total

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The above tables and discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering. The table does not reflect shares of common stock reserved for issuance under our long-term incentive plan, which we plan to adopt in connection with this offering. If the underwriters' option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to , or approximately % of the total number of shares of common stock.

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SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

The following table shows selected historical consolidated financial data of our predecessor, and selected unaudited pro forma financial data for the periods and as of the dates indicated.

The selected historical consolidated financial data as of and for the years ended December 31, 2015 and 2014 were derived from the audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

The selected historical consolidated financial data as of and for the six months ended June 30, 2016 and 2015 were derived from the unaudited historical consolidated financial statements of our predecessor included elsewhere in this prospectus. The selected unaudited historical consolidated financial data has been prepared on a consistent basis with the audited consolidated financial statements of our predecessor. In the opinion of management, such selected unaudited historical consolidated interim financial data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors.

The selected unaudited pro forma statements of operations data for the year ended December 31, 2015 and the six months ended June 30, 2016 has been prepared to give pro forma effect to (i) the reorganization transactions described under "Corporate Reorganization" and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2015. The selected unaudited pro forma balance sheet data has been prepared to give pro forma effect to those transactions as if they had been completed as of June 30, 2016. These data are subject to and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The selected unaudited pro forma financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the reorganization transactions and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

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things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.


	Predecessor												Vantage Energy Inc. Pro Forma

	Six Months Ended June 30,						Year Ended December 31,						Six Months Ended June 30,			Year Ended December 31,

(in thousands, except per share data)	2016			2015			2015			2014			2016			2015

Statement of operations data:
Operating revenues:
Natural gas	$	46,829		$	40,375		$	65,252		$	43,622			$			$
Midstream revenues⁽¹⁾	2,895			2,524			4,054			2,990
Gain (loss) on commodity derivatives	(22,599		)	14,921			51,793			14,434

Total operating revenues	27,125			57,820			121,099			61,046
Operating expenses:
Production and ad valorem taxes⁽²⁾	1,025			512			1,911			1,723
Marketing and gathering	7,961			6,063			9,745			5,333
Lease operating and workover⁽³⁾	1,590			4,451			4,934			2,517
Midstream operating expenses	1,428			831			1,834			891
General and administrative⁽³⁾	4,336			5,487			7,308			5,423
Depreciation, depletion, amortization and accretion	19,490			23,357			39,698			18,302
Impairment of proved oil and gas properties	81,673			—			172,673			—

Total operating expenses	117,503			40,701			238,103			34,189

Operating (loss) income	(90,378		)	17,119			(117,004		)	26,857
Other income (expense)	3			(180		)	(180		)	—
Interest income, net	—			—			—			—
Interest expense, net of capitalized interest⁽⁴⁾	(5,264		)	(4,229		)	(8,778		)	(4,027		)

Income (loss) before income taxes	(5,261		)	(4,409		)	(125,962		)	22,830
Income tax expense (benefit)	—			—			—			—

Net income (loss)	$	(95,639	)	$	12,710		$	(125,962	)	$	22,830			$			$



Balance sheet data (at period end):
Cash	$	15,085		$	8,726		$	2,439		$	21,185			$			$
Total oil and gas properties, net	687,495			486,043			373,786			439,076
Total midstream system, net	59,764			56,458			59,970			53,116
Total assets	780,421			588,640			488,739			551,345
Total debt	244,993			225,087			247,041			197,663
Total members'/stockholders' capital	474,866			339,263			200,093			326,055
Net cash provided by (used in):
Operating activities	$	72,209		$	39,729		$	81,633		$	21,100			$			$
Investing activities	(427,740		)	(78,804		)	(148,852		)	(212,615		)
Financing activities	368,177			26,553			48,473			206,921
Other financial data (unaudited):
E&P Segment Adjusted EBITDA⁽⁵⁾	48,348			28,994			57,229			26,207				107,566			182,020
Midstream Segment Adjusted EBITDA⁽⁶⁾	11,195			6,345			14,056			5,317				22,393			28,112
Adjusted EBITDA⁽⁷⁾	$	59,007		$	40,656		$	69,983		$	31,660			$	128,872		$	207,528
Earnings (loss) per share — basic
Earnings (loss) per share — diluted

(1): Midstream revenues are net of gathering, compression and water fees paid to by Vantage II for historical periods and by Vantage I and Vantage II on a pro forma basis. See "Management's Discussion and Analysis of Financial Condition and Results of Operations — Sources of Revenues — Gathering Revenues".

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(2): Production and ad valorem taxes include expenses recorded for Pennsylvania impact fees, which are annual fees imposed by the state of Pennsylvania on natural gas and oil operators in Pennsylvania for each well drilled for a period of fifteen years.
(3): Lease operating and workover expense includes Council of Petroleum Accountants Society ("COPAS") overhead booked as a reclassification from general and administrative expense on our operated properties and any COPAS charged to us by other operators on our non-operated properties. On a pro forma basis for the six months ended June 30, 2016 and for the year ended December 31, 2015, we recorded allocated COPAS overhead charges of $1.1 million and $2.1 million, respectively. General and administrative expenses are net of overhead recorded to lease operating and workover expenses and the capitalization of certain internal costs. On a pro forma basis for the six months ended June 30, 2016 and the year ended December 31, 2015, we recorded $7.6 million and $13.3 million, respectively, of general and administrative expense, net of allocated COPAS overhead of $1.1 million and $2.1 million, respectively and capitalized general and administrative expenses of $5.1 million and $9.8 million, respectively.
(4): On a pro forma basis for the six months ended June 30, 2016 and for the year ended December 31, 2015, we recorded capitalized interest of $2.9 million and $5.8 million, respectively.
(5): We define E&P Segment Adjusted EBITDA as total revenues from our E&P Segment (including net cash from settlement from commodity derivatives) less E&P Segment operating costs and allocated general and administrative expenses. E&P Segment Adjusted EBITDA for Vantage I was $59.2 million and $124.8 million for the six months ended June 30, 2016 and the year ended December 31, 2015, respectively. Pro forma E&P Segment Adjusted EBITDA represents the sum of the E&P Segment Adjusted EBITDA for our predecessor and Vantage I for such period. See Note 11 and Note 13 to the audited consolidated financial statements of our predecessor and Vantage I, respectively, included elsewhere in this prospectus for a discussion of our segment reporting.
(6): We define Midstream Segment Adjusted EBITDA as total revenues from our Midstream Segment less Midstream Segment operating costs and allocated general and administrative expenses. Midstream Segment Adjusted EBITDA for Vantage I was $11.2 million and $14.1 million for the six months ended June 30, 2016 and the year ended December 31, 2015, respectively. Pro forma Midstream Segment Adjusted EBITDA represents the sum of the Midstream Segment Adjusted EBITDA for our predecessor and Vantage I for such period. See Note 11 and Note 13 to the audited consolidated financial statements of our predecessor and Vantage I, respectively, included elsewhere in this prospectus for a discussion of our segment reporting.
(7): Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss), please see "Prospectus Summary — Non-GAAP Financial Measure".

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Please see "Cautionary Statement Regarding Forward-Looking Statements". Also, please see the risk factors and other cautionary statements described under the heading "Risk Factors" included elsewhere in this prospectus. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the historical financial information presented in "Management's Discussion and Analysis of Financial Condition and Results of Operations" speaks with respect to the combined results of our predecessor and Vantage I, with exception of the select operating results where we have presented the results of each entity individually.

Overview

We conduct our business through two primary reportable segments:

•: Exploration and Production — We explore for and produce oil, natural gas, and NGLs.
•: Midstream — We engage in natural gas gathering and water distribution services for our operations and for third parties.

Exploration and Production

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significant experience in our operating areas. We operate 80 gross horizontal wells in the Marcellus Shale, four gross horizontal wells in the Upper Devonian Shale and 185 gross horizontal wells in the Barnett Shale. We believe that our horizontal drilling and completion expertise, coupled with the favorable geologic characteristics of our Appalachian Basin and Barnett Shale acreage, positions us for continued strong well economics and growth. We have organically grown our net daily production from 18 MMcfe/d for the year ended December 31, 2011 to 398.5 MMcfe/d for the three months ended June 30, 2016, representing a compounded annual growth rate of 98.7%.

Midstream

We do not currently own or operate midstream infrastructure in the Barnett Shale and rely on third-party service providers for the gathering of our production in that basin.

Factors That Significantly Affect Our Financial Condition and Results of Operations

Our revenues are primarily derived from the sale of our natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our production revenues derive entirely from the continental United States. For the year ended December 31, 2015, our production revenues were comprised of approximately 92% from the production and sale of natural gas, approximately 6% from NGLs and approximately 2% from oil. Commodity prices are inherently volatile and are influenced by many factors outside of our control.

We use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks associated with our natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions. We currently use fixed price natural gas swaps for which we receive a fixed swap price for future production in exchange for a payment of the variable market price received at the time future production is sold. The prices contained in natural gas derivative contracts are based on Dominion South Point and WAHA. The prices contained in NGLs and oil derivative contracts are based on OPIS Mont Belvieu and NYMEX West Texas Intermediate ("WTI") prices, respectively. The NYMEX Henry Hub, Inside FERC Dominion and WAHA prices of natural gas, OPIS Mont Belvieu price of NGLs and NYMEX WTI price of oil are widely used benchmarks for the pricing of natural gas, NGLs and oil, respectively, in the United States. The actual prices realized from the sale of natural gas, NGLs and oil differ from the quoted index prices as a result of basis differentials, which result from variances in regional natural gas, NGLs and oil prices compared to index prices as a result of regional supply and demand factors. We are focused

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on maintaining an active hedging program to minimize volatility in cash flows and commodity prices and regional basis differential exposure in an effort to protect our capital investment program as well as expected future cash flows. Although we have at times been able to hedge our natural gas, NGLs and oil production at prices that are higher than current strip prices, in the current commodity price environment, our ability to enter into commodity derivative arrangements at prices higher than current strip prices may be limited, which has the potential to impact the extent to which we can protect our future cash flows. To mitigate the potential negative impact of lower hedge prices, we regularly test available hedge pricing against the economics of our drilling program and limit our hedging activity to contracts with pricing at which our drilling program is economic. Due to changes in drilling and completion costs, operating costs, commodity prices and other factors, this assessment process is dynamic and ongoing.

The following tables provide additional information about our historical hedging activities and results.

Our open positions as of December 31, 2015, covering the period of January 1, 2016 to June 30, 2016, were as follows:


	Predecessor					Vantage Energy I

Commodity	Notional Quantity 1/1/2016 - 6/30/2016		Weighted Average Price			Notional Quantity 1/1/2016 - 6/30/2016		Weighted Average Price

Crude oil swaps (Bbls)		—		$	—		15,558		$	45.66
Natural gas swaps (MMBtu)
Dominion		28,678,000		2.14			15,420,100		2.27
WAHA		—		—			15,091,700		3.04
NYMEX Henry Hub		—		—			—		—

Total		28,678,000		2.14			30,511,800		2.65
NGLs swaps (Gal)
Ethane		—		—			6,946,225		0.21
Propane		—		—			—		—
TetPropane		—		—			2,517,396		0.55
IsoButane		—		—			827,305		0.68
Normal butane		—		—			343,895		0.69
Natural gasoline		—		—			849,407		1.12

Total		—		—			11,484,228		0.40

The following table summarizes the historical results of our hedging activities for the six months ended June 30, 2016:


	For the six months ended June 30, 2016

	Predecessor			Vantage I

Average prices before effects of hedges:
Natural gas (Mcf)		$	1.35		$	1.36
Oil (Bbl)					34.09
NGL (Bbl)					11.09
Average prices after effects of hedges:
Natural gas (Mcf)		$	2.08		$	2.43
Oil (Bbl)					35.93
NGL (Bbl)					12.65

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Our open positions as of December 31, 2014, covering the period of January 1, 2015 to December 31, 2015, were as follows:


	Predecessor					Vantage Energy I

Commodity	Notional Quantity 1/1/2015 - 12/31/2015		Weighted Average Price			Notional Quantity 1/1/2015 - 12/31/2015		Weighted Average Price

Crude oil swaps (Bbls)		—		$	—		95,230		$	90.26
Natural gas swaps (MMBtu)
Dominion		5,475,000		3.13			830,500		3.56
WAHA		—		—			24,086,870		4.10
NYMEX Henry Hub		709,000		4.28			17,988,780		4.25
TETCO M1		—		—			223,000		3.52
TETCO M2		3,582,000		2.12			—		—

Total		9,766,000		2.84			43,129,150		4.15
Henry Hub basis swaps (MMBtu)
Dominion South		—		—			9,125,000		1.01
TETCO M2		—		—			11,230,000		1.28

Total		—		—			20,355,000		1.16
NGLs swaps (Gal)
Ethane		—		—			1,556,010		0.65
Propane		—		—			7,368,165		0.88
TetPropane		—		—			—		—
IsoButane		—		—			1,273,795		1.44
Normal butane		—		—			2,267,080		1.38
Natural gasoline		—		—			2,692,160		1.79

Total		—					15,157,210		1.14

The following table summarizes the historical results of our hedging activities for the year ended December 31, 2015:


	For the year ended December 31, 2015

	Predecessor			Vantage I

Average prices before effects of hedges:
Natural gas (Mcf)		$	1.58		$	1.78
Oil (Bbl)					41.00
NGL (Bbl)					10.45
Average prices after effects of hedges:
Natural gas (Mcf)		$	2.23		$	3.43
Oil (Bbl)					130.06
NGL (Bbl)					21.43

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Our open positions as of December 31, 2013, covering the period of January 1, 2014 to December 31, 2014, were as follows:


	Predecessor					Vantage Energy

Commodity	Notional Quantity 1/1/2014 - 12/31/2014		Weighted Average Price			Notional Quantity 1/1/2014 - 12/31/2014		Weighted Average Price

Crude oil swaps (Bbls)		—		$	—		86,399		$	90.15
Natural gas swaps (MMBtu)
Dominion		2,023,082		4.27			948,911		3.56
WAHA		180,000		3.60			11,839,000		4.00
NYMEX Henry Hub		176,918		3.89			9,221,821		4.22
TETCO M1		500,000		4.29			280,500		3.52

Total		2,880,000		4.21			22,290,232		4.07
NGLs swaps (Gal)				—
Ethane		—		—			1,734,750		0.65
Propane		—		—			5,275,211		0.88
TetPropane		—		—			—		—
IsoButane		—		—			913,783		1.37
Normal butane		—		—			1,622,818		1.32
Natural gasoline		—		—			1,931,238		1.74

Total		—					11,477,800		1.09

The following table summarizes the historical results of our hedging activities for the year ended December 31, 2014:


	For the year ended December 31, 2014

	Predecessor			Vantage I

Average prices before effects of hedges:
Natural gas (Mcf)		$	2.97		$	3.16
Oil (Bbl)					87.35
NGL (Bbl)					24.56
Average prices after effects of hedges:
Natural gas (Mcf)		3.05			3.19
Oil (Bbl)					83.34
NGL (Bbl)					23.85

As of July 31, 2016, we had entered into hedging contracts through 2019 covering a total of approximately 219 TBtu of our projected natural gas, NGLs and oil production at a weighted average price of $2.43 per MMBtu. We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings. Please see "— Quantitative and Qualitative Disclosure About Market Risk" for additional discussion of our commodity derivative contracts.

Like other businesses engaged in the exploration and production of natural gas, NGLs and oil, we face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas, NGLs and oil production from a given well naturally decreases. Thus, a natural gas, NGLs and oil exploration and production company depletes part of its asset base with each unit of natural gas, NGLs and oil it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will

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depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost effective manner and to timely obtain drilling permits and regulatory approvals.

Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:

•: success in drilling new wells;
•: natural gas, NGLs and oil prices;
•: the availability of attractive acquisition opportunities and our ability to execute them;
•: the amount of capital we invest in the leasing and development of our properties;
•: facility or equipment availability and unexpected downtime;
•: delays imposed by or resulting from compliance with regulatory requirements; and
•: the rate at which production volumes on our wells naturally decline.

Market Conditions

The oil and gas industry is cyclical and commodity prices are highly volatile. Since the second half of 2014, commodity prices have declined precipitously and have remained depressed thus far in 2016. Specifically, spot prices for Henry Hub natural gas declined from approximately $4.40 per MMBtu in January 2014 to $3.00 per MMBtu in January 2015, and declined further to less than $1.70 per MMBtu for a brief period in March 2016. Our revenue, profitability and future growth are highly dependent on the prices we receive for our natural gas, NGLs and oil production. Compared to 2014, our realized natural gas price for 2015 dropped 45.6% to $1.68 per Mcf, our realized price for NGLs dropped 57.5% to $10.45 per Bbl and our realized oil price dropped 53.1% to $41.00 per Bbl. Similarly, for the six months ended June 30, 2016, our realized price for natural gas was $1.35 per Mcf, our realized price for NGLs was $11.09 per Bbl and our realized price for oil was $34.09 per Bbl.

Lower commodity prices not only may decrease our revenues, but also may reduce the amount of natural gas, NGLs and oil that we can produce economically and therefore potentially lower our natural gas, NGLs and oil reserves. For example, during 2015, we ran a two rig drilling program with one rig operating in the Appalachian Basin and one rig operating in the Barnett Shale. After temporarily reducing the pace of our drilling and completions activities in the first half of 2016 due to depressed commodity prices, we are currently running two rigs in the Marcellus Shale with the intention of adding a third rig in the Marcellus Shale by year end. Due to our temporary reduction in the pace of our drilling and completion activities in the first half of 2016, our average daily production in the second half of 2016 is anticipated to be lower than our average daily production in the first half of 2016. As a result of our increased drilling and completion activities in the second half of 2016, we anticipate that our average daily production in the first half of 2017 will be materially higher than our average daily production in the second half of 2016. We retain the flexibility to adjust our rig count based on the commodity price environment and other factors.

Our predecessor and Vantage I incurred approximately $81.7 million and $156.0 million of impairment charges during the six months ended June 30, 2016, respectively, and $172.7 million and $344.4 million of impairment charges during 2015, respectively, and lower commodity prices in the future could result in further impairments of our properties, which could have a material adverse

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effect on our results of operations for the periods in which such charges are taken. Lower natural gas, NGLs and oil prices may also reduce the borrowing base under our new revolving credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher natural gas and oil prices may result in significant non-cash fair value losses being incurred on our derivatives, which could cause us to experience net losses when natural gas and oil prices rise.

Recent declines in oil and natural gas prices have had a negative impact on our estimated proved reserves. In the future, a prolonged period of depressed commodity prices may have a significant impact on the value and volumes of our proved reserve portfolio, assuming no other changes in our development plans or costs. If the SEC pricing as of December 31, 2015 (based on average first-of-month prices for the preceding twelve months) for our December 31, 2015 reserve report were replaced with SEC pricing as of June 30, 2016, the estimated future net volumes of our proved reserves on a combined basis would have decreased by 21.1 Bcfe. However, if SEC pricing as of December 31, 2015, which was used for our December 31, 2015 reserve report, had been replaced with forward NYMEX strip prices as of June 30, 2016 for the period through December 2020 and flat thereafter, the estimated future net volumes of our proved reserves on a combined basis would have increased by 87.4 Bcfe. Commodity prices are inherently volatile, and we are unable to predict future commodity prices with any level of certainty.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our predecessor's historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Level of Development Activity. During 2015, we ran a two rig drilling program with one rig operating in the Appalachian Basin and one rig operating in the Barnett Shale. After temporarily reducing the pace of our drilling and completions activities in the first half of 2016 due to commodity prices, we are currently running two rigs in the Marcellus Shale with the intention of adding a third rig in the Marcellus Shale by year end, and we retain the flexibility to adjust our rig count based on the commodity price environment and other factors. Reductions in drilling and completion activity may result in declining levels or natural gas, NGLs and oil production.

Alpha Acquisition. On May 16, 2016, we entered into a purchase and sale agreement with a wholly owned subsidiary of Alpha Natural Resources to purchase certain natural gas properties located in Greene County (the "Alpha Properties") for cash consideration of $339.5 million, subject to post-closing adjustment (the "Alpha Acquisition"). The Alpha Properties consist of approximately 31,323 net acres, of which 5,027 acres are held in fee and leased to third parties, along with non-operating royalty interests in 42 producing Marcellus horizontal wells and certain related midstream and other assets. The Alpha Acquisition was completed in June 2016, with an effective date of April 1, 2016. The Alpha Acquisition added 330 identified drilling locations, including 226 in the Marcellus Shale, 72 in the Upper Devonian Shale and 32 in the Utica Shale. The Alpha Acquisition is shown on a combined basis with our predecessor since the acquisition date.

Corporate Reorganization. The historical consolidated financial statements included in this prospectus are based on the financial statements of our predecessor, Vantage II, prior to our corporate reorganization to be completed in connection with the completion of this offering. In our corporate reorganization, the combination of Vantage I into us will be accounted for at fair value as a business combination by applying the acquisition method, which is expected to significantly alter our full cost pool and increase future depletion costs, among other changes. In addition, we expect to record a significant amount of goodwill in connection with the acquisition of Vantage I for the

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excess of the consideration over the net assets received, representing the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. The fair value of the purchase consideration will be based upon the fair value of the common stock issued in the corporate reorganization. Factors which will impact the allocation of the purchase consideration include the estimated fair value of proved and unproved reserves, the expected timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. Finally, we will also be a taxable entity in future periods. Because Vantage II and Vantage I have assets that substantially overlap and have been operated as a single business under a single management and operational team, we do not expect that the corporate reorganization will have any significant impacts on the manner in which our operations are managed going forward. Please see "Corporate Reorganization". The historical financial data does not include the results of Vantage I and may not give you an accurate indication of what our actual results would have been if the transactions described in "Corporate Reorganization" had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. For more information, please see the audited historical financial statements of Vantage I and the unaudited pro forma financial statements included elsewhere in this prospectus.

Impairment Charges. The natural gas price used in Vantage II's June 30, 2016 ceiling test for impairment, based on the required trailing 12-month average price, was $1.23 per Mcf for Dominion South Point prices proximate to Vantage II's Appalachian Basin operating area. The commodity prices used in Vantage I's June 30, 2016 ceiling test for impairment, based on the required trailing 12-month average price, was $1.23 per Mcf of natural gas for Dominion South Point prices proximate to Vantage I's Appalachian Basin operating area, $2.16 per Mcf of natural gas for WAHA prices proximate to Vantage I's Barnett Shale operating area, $43.00 per Bbl of oil and $15.88 per Bbl of NGLs. To demonstrate the impact of commodity prices on the ceiling calculation, had average prices of $1.29 per Mcf for Dominion South Point prices, $2.19 per Mcf for WAHA prices, $41.30 per Bbl of oil and $15.44 per Bbl of NGLs been used instead, each of Vantage II and Vantage I would not have incurred additional impairment for the six months ended June 30, 2016. The commodity prices for this assumption were calculated based on a 12-month simple average of the commodity prices on the first day of the month for the 11 months ended August 2016 and the price for August 2016 was used for the remaining month in the 12-month average. If prices remain unchanged from this assumption, no impairment will be recognized in the three months ended September 30, 2016.

The above calculation of the impact of lower commodity prices was prepared based on the assumption that all other inputs and assumptions are held constant with the exception of natural gas, NGLs and oil prices. Therefore, this calculation strictly isolates the potential impact of commodity prices on our ceiling test limitation. An amount of any future impairment is difficult to reasonably predict and will depend upon not only commodity prices but also other factors that include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, and all related tax effects. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods and the estimate described above should not be construed as indicative of our development plans or future results.

The ceiling limitation calculation is not intended to be indicative of the fair market value of our proved reserves or future results. Impairment charges do not affect cash flow from operating activities, but do adversely affect our net income (loss) and various components of our balance sheet. Any recorded impairment of oil and gas properties is not reversible at a later date.

Public Company Expenses. Upon completion of this offering, we expect to incur direct, incremental general and administrative ("G&A") expenses as a result of being a publicly traded

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company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, SOX compliance fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation.

Income Taxes. Vantage II is a multi-member limited liability company treated as a partnership for U.S. federal income tax purposes and is not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to the members of each entity. Although we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we do not expect to report any income tax benefit or expense until the consummation of this offering. Based on our deductions primarily related to intangible drilling costs ("IDCs") that are expected to exceed 2016 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities.

Sources of Revenues

Our revenues are derived from the sale of natural gas, NGLs and oil, (including the effects of derivatives), gathering and compression fees collected by our natural gas gathering system and revenues for providing water services. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Natural gas, NGL, and oil sales. We normally sell a large portion of our production to a relatively small number of customers. For the year ended December 31, 2015, sales to Asset Risk Management, South Jersey Industries, Targa Resources and ETC Marketing represented 29%, 20%, 12% and 12% of our total sales, respectively. For the year ended December 31, 2014, sales to Sequent Energy Services, Targa Resources, ETC Marketing and EQT represented 34%, 17%, 12%, and 10% of our total sales, respectively. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of one or several of these customers would have a material adverse effect on our business, as oil and natural gas are fungible products with well-established markets and numerous purchasers.

Midstream revenues. Midstream revenues are generated from gathering, compression and water fees paid by Vantage I, Vantage II and certain third-party working and revenue interest owners. Vantage I and Vantage II both have a 50% working interest in Vantage's midstream assets and, as a result, gathering revenues from midstream assets are allocated 50% to Vantage I and 50% to Vantage II. Gathering revenues received by both Vantage I and Vantage II with regards to their working interest in Vantage's midstream assets are offset in consolidation with the gathering fees paid by Vantage I and Vantage II. As a result, gathering revenues are presented in the statements of operations of Vantage I and Vantage II and are net of the gathering fees paid by Vantage I and Vantage II on their shared midstream infrastructure.

Gains (losses) from commodity derivatives. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a significant portion of our natural gas, NGLs and oil production. We currently use fixed price natural gas swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At the end of each period we estimate the fair value of these swaps and, because we have not elected hedge accounting, we recognize the changes in the fair value of unsettled commodity derivative instruments in earnings at the end of each accounting period. We expect continued volatility in the fair value of these swaps.

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Principal Components of our Cost Structure

•: Production and ad valorem taxes. Production taxes are paid on produced natural gas, oil and NGLs based on a percentage of revenues from production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to the changes in natural gas, oil and NGLs revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our natural gas and oil properties. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. The state of Pennsylvania imposes an impact fee on oil and gas production based on a formula applied towards individual wells. We also record these impact fees in production and ad valorem taxes in the consolidated statement of operations.
•: Midstream. These are costs incurred to bring natural gas to the market. Such costs include the costs to operate and maintain our low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate low- and high-pressure gathering systems that transport our natural gas.
•: Lease operating and workover expenses. These are the day to day operating costs incurred to maintain production of our natural gas and oil producing wells. Such costs include produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for oilfield services.
•: General and administrative expense. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company. Please see "— Factors That Significantly Affect Our Financial Condition and Results of Operations". These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance expenses. General and administrative expenses are reported net of recoveries from other owners in properties operated by us and amounts capitalized pursuant to the full cost method.
•: Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion ("DD&A") includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, oil and NGLs. As a "full cost" company, all costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. Capitalized costs are depleted using the units of production method.
•: Impairment of proved oil and gas properties. Under the full cost method we are required to perform a ceiling test for each cost center. If the net book value of our oil and gas properties exceeds the ceiling, a non-cash impairment is required. See "— Critical Accounting Policies and Estimates" for further discussion.
•: Interest expense. We have financed a portion of our working capital requirements and drilling activities with borrowings under our revolving credit facilities and term loan. As a result, we incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We will likely continue to incur significant interest expense as we continue to grow. Additionally, we capitalized $5.8 million of interest expense for the year ended December 31, 2015.

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Corporate Reorganization

The limited liability company agreements of Vantage Investment I and Vantage Investment II to be adopted in connection with the closing of this offering provide a mechanism by which the shares of our common stock to be allocated amongst the members of Vantage Investment I and Vantage Investment II will be determined. As a result, the satisfaction of all performance, market, and service conditions relative to the incentive unit awards held by certain Management Members will be probable. Accordingly, we will recognize approximately $ million in a non-cash charge for incentive compensation expense for the estimated fair value of those awards at the closing of this offering. The charge will not have a dilutive effect on the pro forma net tangible book value per share to new investors in this offering.

Because consideration for the membership interests awards will be deemed given by Vantage Investment II, the charge to expense will be accounted for as capital contributions by Vantage Investment II to us and credited to additional paid-in capital.

Vantage II (Predecessor) Results of Operations

Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

Below are some highlights of our financial and operating results for the three months ended June 30, 2016:

•: Our production volumes increased 79.1% to 18,932 MMcfe for the three months ended June 30, 2016 compared to 10,573 MMcfe for the three months ended June 30, 2015.
•: Natural gas sales revenues increased 84.1% to $26.1 million for the three months ended June 30, 2016 compared to $14.2 million for the three months ended June 30, 2015.

The following table sets forth selected operating data for the three months ended June 30, 2016 compared to the three months ended June 30, 2015:


	Predecessor

	For the Three Months Ended June 30,					Amount of

(in thousands)	2016			2015		Change

Revenues:
Natural gas sales	$	26,055		$	14,152		$	11,903
Midstream revenues	1,732			1,142			590
Gain (loss) on commodity derivatives	(34,507		)	6,725			(41,232		)

Total revenues	(6,720		)	22,019			(28,739		)
Operating expenses:
Production and ad valorem taxes	574			288			286
Marketing and gathering	5,237			2,758			2,479
Lease operating and workover	1,242			1,814			(572		)
Midstream operating	416			416			—
General and administrative	2,432			2,260			172
Depreciation, depletion, amortization and accretion	10,150			9,481			669
Impairment of proved oil and gas properties	15,952			—			15,952

Total operating expenses	36,003			17,017			18,986

Operating (loss) income	(42,723		)	5,002			(47,725		)

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	Predecessor

	For the Three Months Ended June 30,						Amount of

(in thousands)	2016			2015			Change

Other expenses:
Other income (expense)	3			(180		)		183
Interest expense, net of capitalized income	(2,844		)	(2,766		)		(78		)

Total other expenses	(2,841		)	(2,946		)		105
Net income (loss)	$	(45,564	)	$	2,056			$	(47,620	)



SEGMENT FINANCIAL DATA — E&P
Natural gas, NGL and oil sales	$	26,055		$	14,152			$	11,903
Gain (loss) on commodity derivatives	(34,507		)	6,725				(41,232		)

Total realized revenues	(8,452		)	20,877				(29,329		)
Operating expenses	11,328			7,685				3,643
Gathering and compression expenses	—			(45		)		45
Allocated general and administrative expenses	2,131			1,946				186
Other income (expense)	3			(180		)		183
Total (gains) losses on derivative, net, less net cash from settlement of commodity derivatives	44,681			(109		)		44,790

Adjusted EBITDA	$	22,773		$	11,002			$	11,771
SEGMENT FINANCIAL DATA — Midstream
Gathering and compression revenues	$	6,055		$	3,967			$	2,088
Water revenues	1,353			—				1,353

Total realized revenues	7,408			3,967				3,441
Gathering and compression operating expenses	416			461				(45		)
Water system expenses	1,649			—				1,649
Allocated general and administrative expenses	301			314				(13		)

Adjusted EBITDA	$	5,042		$	3,192			$	1,850
OPERATIONAL DATA
Production Data:
Natural gas (MMcf)	18,932			10,573				8,359
Midstream Data:
Throughput (MMcf)	11,742			8,087				3,655
Water volumes (MBbl)	348			—				348
Average prices before effects of hedges per Mcf:
Natural gas	$	1.38		$	1.34			$	0.04
Average prices after effects of hedges per Mcf⁽¹⁾:
Natural gas	$	1.91		$	1.96			$	(0.05	)
Average cost per Mcf:
Production and ad valorem taxes	$	0.03		$	0.03			$	0.00
Marketing and gathering	0.28			0.26				$	0.02
Lease operating and workover expenses	0.07			0.17				$	(0.10	)
General and administrative	0.13			0.21				$	(0.08	)
Depreciation, depletion, amortization and accretion	0.54			0.90				$	(0.36	)

(1): The effect of hedges includes realized gains and losses on commodity derivative transactions.

Natural gas sales revenues. Natural gas revenue increased $11.9 million, or 84.1%, from $14.2 million during the three months ended June 30, 2015 to $26.1 million during the three months ended June 30, 2016. The increase is primarily attributable an increase in production volumes of 79.1% and to a lesser extent due to a 3.0% increase in realized natural gas prices from $1.34 per Mcf for the three months ended June 30, 2015 to $1.38 per Mcf for the three months ended June 30, 2016.

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Midstream revenues. Midstream revenue increased $0.6 million, or 51.7%, to $1.7 million during the three months ended June 30, 2016 from $1.1 million during the three months ended June 30, 2015 due to the higher production from new wells, partially offset by production declines on certain pads.

Gain (loss) on commodity derivatives. Gains on commodity derivatives decreased 613%, to a loss of $34.5 million during the three months ended June 30, 2016 from a gain of $6.7 million during the three months ended June 30, 2015. The $34.5 million loss on commodity derivatives during the three months ended June 30, 2016 was comprised of $44.7 million in losses due to the change in fair value of the derivative contracts and $10.2 million of cash received upon contract settlements. The $6.7 million gain during the three months ended June 30, 2015 was comprised of $0.1 million in gains due to the change in fair value of the derivative contracts and $6.6 million of cash received upon contract settlements. The decrease in unrealized fair value is primarily attributable to an increase in commodity prices. Commodity derivative fair value gains or losses will vary on future commodity prices and have no cash flow impact until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.3 million to $0.6 million during the three months ended June 30, 2016 from $0.3 million during the three months ended June 30, 2015. The increase in impact fees is primarily due to increased drilling during the three months ended June 30, 2016 compared to the three months ended June 30, 2015. These fees are accrued when a well is spud.

Marketing and gathering. Marketing and gathering expenses for the three months ended June 30, 2016 were $5.2 million, compared to $2.8 million for the three months ended June 30, 2015 due to higher production from new wells, partially offset by production declines on certain pads.

Midstream operating. Midstream operating expenses were virtually unchanged for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 at $0.4 million.

Lease operating and workover expenses. Lease operating and workover expenses decreased to $1.2 million during the three months ended June 30, 2016 from $1.8 million during the three months ended June 30, 2015. The decrease is primarily due to reduced salt water disposal costs arising from the re-use of water in drilling and completion operations as opposed to incurring disposal costs of the water at commercial facilities. As a result, salt water disposal costs decreased to $0.5 million for the three months ended June 30, 2016 from $1.1 million for the three months ended June 30, 2015, representing a decrease from $0.11 per Mcf to $0.02 per Mcf.

General and administrative expense. General and administrative expenses increased to $2.4 million during the three months ended June 30, 2016 from $2.3 million during the three months ended June 30, 2015 as a result of higher labor costs partially offset by increased capitalized general and administrative expenses. General and administrative expenses are net of overhead recoveries from third parties and capitalized general and administrative expenses of $1.2 million and $0.6 million for the three months ended June 30, 2016 and 2015, respectively. The increase in overhead recoveries and capitalized general and administrative expense is primarily related to increased acquisition, drilling and completion activities during the three months ended June 30, 2016 compared to the three months ended June 30, 2015. The increase in labor related expenses is primarily the result of an increase in salaries and wages from a higher headcount. We expect general and administrative expenses to increase in future periods as a result of additional public company expenses.

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Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion expenses increased to $10.2 million during the three months ended June 30, 2016 from $9.5 million during the three months ended June 30, 2015. The increase is primarily the result of a 79.1% increase in production, partially offset by a 42.1% decrease in the depletion rate from $0.82 per MMcfe for the three months ended June 30, 2015 to $0.47 per MMcfe for the three months ended June 30, 2016. The decrease in the depletion rate was primarily due to $238.4 million in impairment charges incurred after the second quarter of 2015.

Impairment of proved oil and gas properties. Impairment for the three months ended June 30, 2016 was $16.0 million, compared to zero for the three months ended June 30, 2015. The impairment is primarily the result of decreases in the trailing 12-month average prices for natural gas. If pricing conditions decline further, we will incur full cost ceiling impairments in future quarters, the magnitude of which will be affected by one or more of the other components of the ceiling test calculations, until prices stabilize or improve over a twelve-month period. For a discussion of the Vantage II asset impairments, see Note 1 to the unaudited condensed consolidated financial statements of Vantage II included elsewhere in this prospectus.

Interest expense, net of capitalized interest. Interest expense was comparable between periods at $2.8 million in each of the three months ended June 30, 2016 and 2015.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Below are some highlights of our financial and operating results for the six months ended June 30, 2016:

•: Our production volumes increased 57.6% to 34,759 MMcfe for the six months ended June 30, 2016 compared to 22,054 MMcfe for the six months ended June 30, 2015.
•: Natural gas sales revenues increased 16.0% to $46.8 million for the six months ended June 30, 2016 compared to $40.4 million for the six months ended June 30, 2015.

The following table sets forth selected operating data for the six months ended June 30, 2016 compared to the six months ended June 30, 2015:


	Predecessor

	For the Six Months Ended June 30,					Amount of

(in thousands)	2016			2015		Change

Revenues:
Natural gas sales	$	46,829		$	40,375		$	6,454
Midstream revenues	2,895			2,524			371
Gain (loss) on commodity derivatives	(22,599		)	14,921			(37,520		)

Total revenues	27,125			57,820			(30,695		)
Operating expenses:
Production and ad valorem taxes	1,025			512			513
Marketing and gathering	7,961			6,063			1,898
Lease operating and workover	1,590			4,451			(2,861		)
Midstream operating	1,428			831			597
General and administrative	4,336			5,487			(1,151		)
Depreciation, depletion, amortization and accretion	19,490			23,357			(3,867		)
Impairment of proved oil and gas properties	81,673			—			81,673

Total operating expenses	117,503			40,701			76,802

Operating (loss) income	(90,378		)	17,119			(107,497		)

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	Predecessor

	For the Six Months Ended June 30,						Amount of

(in thousands)	2016			2015			Change

Other expenses:
Other income (expense)	3			(180		)		183
Interest expense, net of capitalized income	(5,264		)	(4,229		)		(1,035		)

Total other expenses	(5,261		)	(4,409		)		(852		)
Net income (loss)	$	(95,639	)	$	12,710			$	(108,349	)



SEGMENT FINANCIAL DATA — E&P
Natural gas, NGL and oil sales	$	46,829		$	40,375			$	6,454
Gain (loss) on commodity derivatives	(22,599		)	14,921				(37,520		)

Total realized revenues	24,230			55,296				(31,066		)
Operating expenses	20,399			16,321				4,078
Gathering and compression expenses	—			(45		)		45
Allocated general and administrative expenses	3,705			4,889				(1,184		)
Other income (expense)	3			(180		)		183
Total (gain) losses on derivative, net, less net cash from settlement of commodity derivatives	48,219			(4,957		)		53,176

Adjusted EBITDA	$	48,348		$	28,994			$	19,354
Other
Total assets	$	720,116		$	531,830			$	188,286
Capital expenditures	$	426,086		$	70,809			$	355,277
SEGMENT FINANCIAL DATA — Midstream
Gathering and compression revenues	$	12,767		$	7,819			$	4,948
Water revenues	3,944			—				3,944

Total realized revenues	16,711			7,819				8,892
Gathering and compression operating expenses	1,428			876				552
Water system expenses	3,457			—				3,457
Allocated general and administrative expenses	631			598				33

Adjusted EBITDA	$	11,195		$	6,345			$	4,850
Other
Total assets	$	63,703		$	57,664			$	6,039
Capital expenditures	$	2,427		$	7,995			$	(5,568	)
OPERATIONAL DATA
Production Data:
Natural gas (MMcf)	34,759			22,054				12,705
Midstream Data:
Throughput (MMcf)	24,164			15,709				8,455
Water volumes (MBbl)	1,097			—				1,097
Average prices before effects of hedges per Mcf:
Natural gas	$	1.35		$	1.83			$	(0.48	)
Average prices after effects of hedges per Mcf⁽¹⁾:
Natural gas	$	2.08		$	2.28			$	(0.20	)
Average cost per Mcf:
Production and ad valorem taxes	$	0.03		$	0.02			$	0.01
Marketing and gathering	0.23			0.27				$	(0.04	)
Lease operating and workover expenses	0.05			0.20				$	(0.15	)
General and administrative	0.12			0.25				$	(0.13	)
Depreciation, depletion, amortization and accretion	0.56			1.06				$	(0.50	)

(1): The effect of hedges includes realized gains and losses on commodity derivative transactions.

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Natural gas sales revenues. Natural gas revenue increased $6.5 million, or 16.0%, from $40.4 million during the six months ended June 30, 2015 to $46.8 million during the six months ended June 30, 2016. The increase is primarily attributable to a 57.6% increase in production volumes, partially offset by a 26.4% decrease in realized natural gas prices from $1.83 per Mcf for the six months ended June 30, 2015 to $1.35 per Mcf for the six months ended June 30, 2016.

Midstream revenues. Midstream revenue increased $0.4 million, or 14.7%, to $2.9 million during the six months ended June 30, 2016 from $2.5 million during the six months ended June 30, 2015 due to the higher production from new wells, partially offset by production declines on certain pads.

Gain (loss) on commodity derivatives. Gains on commodity derivatives decreased 251%, to a loss of $22.6 million, during the six months ended June 30, 2016 from a gain of $14.9 million during the six months ended June 30, 2015. The $22.6 million loss on commodity derivatives during the six months ended June 30, 2016 was comprised of $48.2 million in losses due to the change in fair value of the derivative contracts and $25.6 million of cash received upon contract settlements. The $14.9 million gain during the six months ended June 30, 2015 was comprised of $4.9 million in gains due to the change in fair value of the derivative contracts and $10.0 million of cash received upon contract settlements. The decrease in unrealized fair value is primarily attributable to an increase in commodity prices. Commodity derivative fair value gains or losses will vary on future commodity prices and have no cash flow impact until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments.

Production and ad valorem taxes. Production and ad valorem taxes increased $0.5 million to $1.0 million during the six months ended June 30, 2016 from $0.5 million during the six months ended June 30, 2015. The increase in impact fees is primarily due to increased drilling during the six months ended June 30, 2016 compared to the six months ended June 30, 2015. These fees are accrued when a well is spud.

Marketing and gathering. Marketing and gathering expenses for the six months ended June 30, 2016 increased $1.9 million, or 31.3%, to $8.0 million from $6.1 million for the six months ended June 30, 2015 due to higher production from new wells, partially offset by production declines on certain pads.

Midstream operating. Midstream operating expenses for the six months ended June 30, 2016 were $1.4 million, compared to $0.8 million for the six months ended June 30, 2015. The increase is due to additional compression and other operating costs related to increased system throughput.

Lease operating and workover expenses. Lease operating and workover expenses decreased to $1.6 million during the six months ended June 30, 2016 from $4.5 million during the six months ended June 30, 2015. The decrease is primarily due to reduced salt water disposal costs arising from the re-use of water in drilling and completion operations as opposed to disposal of the water at commercial facilities. As a result, salt water disposal costs decreased to $0.6 million for the six months ended June 30, 2016 from $3.0 million for the six months ended June 30, 2015, representing a decrease from $0.14 per Mcf to $0.02 per Mcf.

General and administrative expense. General and administrative expenses decreased to $4.3 million during the six months ended June 30, 2016 from $5.5 million during the six months ended June 30, 2015 primarily due to increased capitalized general and administrative expenses and lower labor costs. General and administrative expenses are net of overhead recoveries from third parties and capitalized general and administrative expenses of $2.7 million and $1.9 million for the six months ended June 30, 2016 and 2015, respectively. The increase in overhead recoveries and capitalized general and administrative expenses is primarily related to increased acquisition,

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drilling and completion activities during the six months ended June 30, 2016 compared to the six months ended June 30, 2015. The decrease in labor related expenses is primarily the result of a $0.7 million reduction in compensation expense related to bonuses partially offset by an increase in salaries and wages from a higher headcount. We expect general and administrative expenses to increase in future periods as a result of additional public company expenses.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion expenses decreased to $19.5 million during the six months ended June 30, 2016 from $23.4 million during the six months ended June 30, 2015. The decrease is primarily the result of $238.4 million in impairment charges incurred after the first quarter 2015, which contributed to a decrease in the depletion rate to $0.50 per MMcf for the six months ended June 30, 2016 from $0.98 per MMcfe for the six months ended June 30, 2015. The decrease was partially offset by an increase in production to 34,759 MMcf from 22,054 MMcf for the respective periods.

Impairment of proved oil and gas properties. Impairment for the six months ended June 30, 2016 was $81.7 million, compared to zero for the six months ended June 30, 2015. The impairment is primarily the result of decreases in the trailing 12-month average prices for natural gas. If pricing conditions decline further, we will incur full cost ceiling impairments in future quarters, the magnitude of which will be affected by one or more of the other components of the ceiling test calculations, until prices stabilize or improve over a twelve-month period. For a discussion of the Vantage II asset impairments, see Note 1 to the unaudited condensed combined financial statements of Vantage II included elsewhere in this prospectus.

Interest expense, net of capitalized interest. The increase of $1.0 million is primarily attributable to an increase in outstanding revolving credit facility balances from $127.0 million at June 30, 2015 to $146.2 million at June 30, 2016, as well as an increase in the average interest rate on the revolving credit facility from 2.68% for the six months ended June 30, 2015 to 3.41% for the six months ended June 30, 2016.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Below are some highlights of our financial and operating results for the year ended December 31, 2015:

•: Our production volumes increased 180.7% to 41,216 MMcf in the year ended December 31, 2015 compared to 14,683 MMcf in the year ended December 31, 2014.
•: Our natural gas sales increased 49.6% to $65.3 million in the year ended December 31, 2015 compared to $43.6 million in the year ended December 31, 2014.
•: Our per unit lease operating and workover expenses decreased 30.2% to $0.12 per Mcf in the year ended December 31, 2015 compared to $0.17 per Mcf in the year ended December 31, 2014.

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The following table sets forth selected operating data for the year ended December 31, 2015 compared to the year ended December 31, 2014:


	Predecessor

	For the Year Ended December 31,						Amount of

(in thousands)	2015			2014			Change

Revenues:
Natural gas sales	$	65,252		$	43,622			$	21,630
Midstream revenues	4,054			2,990				1,064
Gain (loss) on commodity derivatives	51,793			14,434				37,359

Total revenues	121,099			61,046				60,053
Operating expenses:
Production and ad valorem taxes	1,911			1,723				188
Marketing and gathering	9,745			5,333				4,412
Lease operating and workover	4,934			2,517				2,417
Midstream operating	1,834			891				943
General and administrative	7,308			5,423				1,885
Depreciation, depletion, amortization and accretion	39,698			18,302				21,396
Impairment of proved oil and gas properties	172,673			—				172,673

Total operating expenses	238,103			34,189				203,914

Operating (loss) income	(117,004		)	26,857				(143,861		)
Other expenses:
Other income (expense)	(180		)	—				(180		)
Interest expense, net of capitalized income	(8,778		)	(4,027		)		(4,751		)

Total other expenses	(8,958		)	(4,027		)		(4,931		)
Income tax expense (benefit)	—			—				—
Net income (loss)	$	(125,962	)	$	22,830			$	(148,792	)



SEGMENT FINANCIAL DATA — E&P
Natural gas, NGL and oil sales	$	65,252		$	43,622			$	21,630
Gain (loss) on commodity derivatives	51,793			14,434				37,359

Total realized revenues	117,045			58,056				58,989
Operating expenses	28,292			13,804				14,488
Allocated general and administrative expenses	6,140			4,546				1,594
Other income (expense)	(180		)	—				(180		)
Total (gains) losses on derivative, net, less net cash from settlement of commodity derivatives	(25,204		)	(13,499		)		(11,705		)

Adjusted EBITDA	$	57,229		$	26,207			$	31,022
Other
Total assets	$	429,321		$	497,806			$	(68,485	)
Capital expenditures	$	135,524		$	176,799			$	(41,275	)
SEGMENT FINANCIAL DATA — Midstream
Gathering and compression revenues	$	15,756		$	7,085			$	8,671
Water revenues	5,487			—				5,487

Price to the public

Underwriting discounts and commissions⁽¹⁾

Proceeds to us (before expenses)

Vantage Energy Inc. S-1